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, 2008




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
            
            The
      NASDAQ Stock Market LLC




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 *No R





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. YesRNo*





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 R
            Accelerated filer*
            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 $796.0
million on June 30, 2008, based on $23.05 per unit, the closing price of the
Common Units as reported on The NASDAQ Stock Market LLC on such
date.





As of
February 1, 2009, there were 34,684,000 Common Units, 11,528,231 Subordinated
Units and 943,108 General Partner Units outstanding.





DOCUMENTS
INCORPORATED BY REFERENCE




None















TABLE OF CONTENTS




DESCRIPTION




PART I1.
                                        
                                        BUSINESS
                                        21A.
                                        
                                        RISK FACTORS
                                        191B.
                                        
                                        UNRESOLVED STAFF COMMENTS
                                        392.
                                        
                                        PROPERTIES
                                        403.
                                        
                                        LEGAL PROCEEDINGS
                                        404.
                                        
                                        SUBMISSION OF MATTERS TO A VOTE OF SECURITY
      HOLDERS
                                        40PART II5.
                                        
                                        MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
      MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
                                        416.
                                        
                                        SELECTED FINANCIAL DATA
                                        437.
                                        
                                        MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
      AND RESULTS OF OPERATIONS
                                        487A.
                                        
                                        QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
      RISK
                                        688.
                                        
                                        FINANCIAL STATEMENTS AND SUPPLEMENTARY
      DATA
                                        719.
                                        
                                        CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
      ACCOUNTING AND FINANCIAL DISCLOSURE
                                        719A.
                                        
                                        CONTROLS AND PROCEDURES
                                        719B.
                                        
                                        OTHER INFORMATION
                                        71PART III10.
                                        
                                        DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
      GOVERNANCE
                                        7211.
                                        
                                        EXECUTIVE COMPENSATION
                                        7612.
                                        
                                        SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
      OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
                                        9113.
                                        
                                        CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
      DIRECTOR INDEPENDENCE
                                        9314.
                                        
                                        PRINCIPAL ACCOUNTANT FEES AND
SERVICES
                                        99PART IV15.
                                        
                                        EXHIBITS AND FINANCIAL STATEMENT
      SCHEDULES
                                        100











TABLE OF CONTENTS


PART I





CAUTIONARY
STATEMENT ABOUT FORWARD-LOOKING STATEMENTS





Targa Resources Partners LP’s (together
with its subsidiaries (“we,” “us,” “our” 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:











1
 TABLE OF CONTENTS


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 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 units, a measure of heating valueBcf
            Billion
      cubic feetBtu
            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
      IndexDefinitionsIF-HSC
            Inside
      FERC Gas Market Report, Houston Ship Channel/Beaumont,
    TexasIF-NGPL
      MC
            MC
      Inside FERC Gas Market Report, Natural Gas Pipeline,
      Mid-ContinentIF-Waha
            Inside
      FERC Gas Market Report, West Texas WahaNY-HH
            NYMEX,
      Henry Hub Natural GasNY-WTI
            NYMEX,
      West Texas Intermediate Crude OilOPIS-MB
            Oil
      Price Information Service, Mont Belvieu,
Texas








Item
1. Business





Overview





Targa
Resources Partners LP (NASDAQ: NGLS) is a growth-oriented 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
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 NGL and NGL products.





We
currently operate in the Fort Worth Basin/Bend Arch in North Texas (the
“Fort Worth Basin”), the Permian Basin of West Texas and in Southwest
Louisiana. We generally gather natural gas from producers at the wellhead or
central delivery points, move the wellhead natural gas through our gathering
system, treat and process the natural gas and then sell the resulting residue
natural gas and NGLs based on published index market prices.


2
 TABLE OF CONTENTS





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. 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.





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.





Successful
execution of larger organic growth projects and acquisitions is highly dependent
on our access to the equity and debt capital markets. Given the current
challenging conditions in the capital markets and the outlook for weak commodity
prices, we expect that growth opportunities will be subject to more stringent
evaluation criteria and that expenditure levels will moderate to preserve
capital until economic and financial market conditions improve.





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





·
            Increasing the profitability
      of our existing assets. With our
      North Texas System, we have an extensive network of gathering systems and
      two natural gas processing facilities, which positions us to capitalize on
      ongoing development from the Barnett Shale and the other Fort Worth
      Basin formations. The SAOU System is located in the Permian Basin of West
      Texas, which is characterized by long-lived, multi-horizon oil and gas
      reserves that have low natural production declines. The LOU System has
      access to onshore basins in South Louisiana and serves the Lake Charles
      industrial market. Our assets provide us opportunities
  to:





·
            utilize
      excess pipeline and plant capacity to connect and process new supplies of
      natural gas at minimal incremental
cost;





·
            undertake
      additional initiatives to improve operating efficiencies and increase
      processing yields;





·
            eliminate
      bottlenecks to allow for increased
throughput;





·
            pursue
      pressure reduction projects to increase volumes of gas to be gathered and
      processed; and





·
            expand
      our footprint in a cost effective
manner.





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


3
 TABLE OF CONTENTS





·
            Mitigating commodity price
      exposure through prudent hedging arrangements.The
      primary purpose of our commodity price risk management activities is to
      hedge our exposure to commodity price risk inherent in our contract mix
      and reduce fluctuations in our operating cash flow despite fluctuations in
      commodity prices. We have hedged the commodity price associated with a
      portion of our expected natural gas, NGLs and condensate equity volumes
      for the years 2009 through 2012 by entering into derivative financial
      instruments including swaps and purchased puts (or floors). The
      percentages of our expected equity volumes that are covered by our hedges
      decrease over time. We have structured our hedges to approximate our
      actual NGL product composition and to approximate our actual NGL and
      natural gas delivery points. We do not use crude oil prices to approximate
      NGL prices for purposes of hedging. We intend to continue to manage our
      exposure to commodity prices in the future by entering into similar hedge
      transactions using swaps, collars, purchased puts (or floors) or other
      hedge instruments as market conditions warrant. During prolonged periods
      of low commodity prices or low liquidity in forward markets, we may elect
      to hedge a lower portion of our exposure.  Concerns regarding
      hedge counterparty credit quality may impact our desire or ability to
      enter into new hedging
arrangements.





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





·
            Focusing on producing regions
      with attractive characteristics.We
      seek to focus on those regions and supplies with attractive
      characteristics, including regions:





·
            where
      treating or processing is required to access
  end-markets;





·
            with
      a strong base of current production and the potential for future
      development;





·
            where
      permitting, drilling and workover activity is
  high;





·
            with
      the potential for long-term acreage dedications;
  and





·
            that
      can serve as a platform to expand into adjacent areas with existing or new
      production.





·
            Pursuing strategic and
      accretive acquisitions. We plan to pursue strategic and
      accretive acquisition opportunities within the midstream energy industry,
      both from Targa and from third parties. We will seek acquisitions in our
      existing areas of operation that provide the opportunity for operational
      efficiencies, the potential for higher capacity utilization and expansion
      of existing assets, acquisitions in other related midstream businesses
      and/or expansion into new geographic areas of 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.
      Current disruptions in the financial markets has made obtaining equity or
      debt funding on acceptable terms more difficult, which 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.


4
 TABLE OF CONTENTS


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. Targa owns and operates a
      large integrated platform of midstream assets in oil and natural gas
      producing regions, including the Permian Basin in West Texas and Southeast
      New Mexico and the onshore and offshore regions of the Texas and Louisiana
      Gulf Coast. These operations are integrated with Targa’s NGL logistics and
      marketing business that extends services to customers throughout the U.S.
      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.





·
            Strategically located
      assets.





Our North
Texas System is one of the largest integrated natural gas gathering,
compression, treating and processing systems in the Fort Worth Basin. We
believe current levels of natural gas exploration, development and production
activities within the Fort Worth Basin present opportunities to generate
additional throughput on our system.





The SAOU
System provides us access to the Permian Basin, which is characterized by
long-lived, multi-horizon oil and gas reserves that have low natural production
declines. The SAOU System has access to liquid market hubs for both natural gas
and NGLs.





The LOU
System gathers gas primarily from onshore oil and gas production in Southwest
Louisiana in the area around and between Lafayette and Lake Charles, Louisiana.
The LOU System’s processing plants have direct access to the Lake Charles
industrial market through its intrastate pipeline system, providing us the
ability to deliver natural gas to industrial users and electric utilities in the
Lake Charles area. The LOU System also has access to both interstate natural gas
supplies and markets as well as access to the NGL markets of the Louisiana and
Texas Gulf Coast.





·
            High quality and efficient
      assets. Our gathering and processing systems consist of high
      quality assets that have been well maintained, resulting in low cost,
      efficient operations. We have implemented state-of-the-art processing,
      measurement and operations and maintenance technologies. These
      technologies have allowed us to proactively manage our operations with
      fewer field personnel resulting in lower costs and minimal downtime. As a
      result, we believe we have established a reputation in the midstream
      business as a reliable and cost-effective supplier of services to our
      customers and have a track record of safe, efficient and reliable
      operation of our facilities.





·
            Low maintenance capital
      expenditures. We believe that a relatively low level of
      maintenance capital expenditures is sufficient for us to continue
      operations in a safe, prudent and cost-effective
  manner.





·
            Prudent hedging
      arrangements. While our percent-of-proceeds gathering and
      processing contracts subject us to commodity price risk, we have entered
      into long-term hedges covering the commodity price exposure associated
      with a significant portion of our near to mid-term expected equity gas,
      condensate and NGL volumes.





·
            Strong producer customer base.We have a strong producer customer base consisting of both major
      oil and gas companies and other producers. We believe we have established
      a reputation as a reliable operator by providing high quality services and
      focusing on the needs of our customers. Targa also has relationships
      throughout the energy industry, including with producers of natural gas in
      the U.S. and has established a positive reputation in the energy business
      which we believe will assist us in our primary business
      objectives.


5
 TABLE OF CONTENTS





·
            Comprehensive package of
      midstream services. We provide a comprehensive package of
      services to natural gas producers, including natural gas gathering,
      compression, treating, processing and NGL fractionating. We believe our
      ability to provide these services provides us with an advantage in
      competing for new supplies of natural gas because we can provide
      substantially all of the services producers, marketers and others require
      to move natural gas and NGLs from wellhead to market on a cost-effective
      basis.





·
            Experienced management
      team. Targa’s executive management team members have over 200
      years of combined experience operating, acquiring, integrating and
      improving the value of midstream natural gas assets and businesses across
      major supply areas including Texas, Louisiana and the Gulf Coast and have
      held management positions at companies with midstream assets and
      commercial operations similar in scale and scope to ours. Several of
      Targa’s executive and senior management team members have worked together
      effectively in prior roles.  In addition, Targa’s operations and
      commercial management team consists of individuals with an average of
      approximately 25 years of midstream operating experience. Our relationship
      with Targa provides us with access to significant operational, commercial,
      technical, risk management and other
expertise.





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 ability
to finance our operations,our ability 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.”





Our
Relationship with Targa Resources, Inc.





One of
our principal strengths is our relationship with Targa, a leading provider of
midstream natural gas and NGL services in the U.S. Targa was formed in 2004 by
its management team, which consists of former members of senior management of
several midstream and other diversified energy companies and Warburg Pincus LLC
(“Warburg Pincus”), a private equity firm. In April 2004, Targa purchased the
SAOU and LOU Systems from ConocoPhillips Company (“ConocoPhillips”), for
$247 million and, in October 2005, Targa purchased substantially all of the
midstream assets of Dynegy Inc. (“Dynegy”) for approximately $2.5 billion.
These transactions formed a large-scale, integrated midstream energy company
with the ability to offer a wide range of midstream services to a diverse group
of natural gas and NGL producers and customers. As of December 31, 2008,
Targa had total assets of approximately $3.6 billion (including the assets
of the Partnership, which represent approximately $1.6 billion of this
amount).





Targa
conducts its business operations through two divisions and reports its results
of operations under four segments: Natural Gas Gathering and Processing
division, which includes the Partnership, is a single segment consisting of
Targa’s  natural gas gathering and processing facilities, as well as
certain fractionation capability integrated within those facilities; and the NGL
Logistics and Marketing division, which consists of three segments: Logistics
Assets, NGL Distribution and Marketing, and Wholesale Marketing.





Natural Gas Gathering and
Processing—Targa gathers and processes natural gas from the Permian
Basin, North Texas, the onshore region of the Louisiana Gulf Coast and the Gulf
of Mexico. Most of the NGLs Targa processes are supplied through its gathering
systems which, in aggregate, consist of approximately 11,000 miles of
natural gas pipelines. The remainder is supplied through third party owned
pipelines. Targa’s processing plants include 16 facilities that it operates
(either wholly or jointly) as well as six facilities in which it has an
ownership interest but are operated by others. For 2008, these assets processed
an average inlet plant volume of approximately 1.8 Bcf/d of natural gas and
produced an average of approximately 87 MBbl/d of NGLs, in each case, net
to Targa’s ownership interests.


6
 TABLE OF CONTENTS





NGL Logistics and
Marketing—Targa has a significant, integrated NGL logistics and
marketing business with net NGL fractionation capacity of approximately
300 MBbl/d and 36 owned and operated storage wells with a net storage
capacity of approximately 65 MMBbl and 17 storage, marine and transport
terminals with an NGL above ground storage capacity of approximately
900 MBbl. This division uses its extensive platform of integrated assets to
fractionate, store, terminal, transport, distribute and market NGLs, typically
under fee-based and margin-based arrangements. Its assets are generally
connected to and supplied, in part, by its 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. Targa owns, operates or leases assets in a number of other
states, including Alabama, Nevada, California, Florida, Mississippi, Tennessee,
New Jersey and Kentucky. The geographic diversity of Targa’s assets provides it
direct access to many NGL end-users in both its geographic markets as well as
markets outside its operating regions via open-access regulated NGL pipelines
owned by third parties. Targa also owns 21 pressurized NGL barges, owns and
leases approximately 70 transport tractors and owns 100 tank trailers and leases
and manages approximately 770 railcars.





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 to
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. While Targa believes it will be in its best interest to
contribute additional assets to us given its significant ownership of limited
and general partner interests in us, Targa constantly evaluates acquisitions and
dispositions and may elect to acquire, construct or dispose of midstream assets
in the future without offering us the opportunity to purchase or construct those
assets. 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.





Targa has
a significant indirect interest in our partnership through its ownership of a
24.5% 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 with them 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 950 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.”





7
 TABLE OF CONTENTS


Our
Systems





Our
natural gas gathering and processing operations are located in and serve parts
of three geographic regions: the North Texas System in the Fort Worth
Basin, the SAOU System in the Permian Basin and the LOU System in Southwestern
Louisiana.





The
following table summarizes key ownership and operational information regarding
our operating gathering systems and natural gas processing plants, all of which
are 100% owned and operated:





Facility
                                    Location
                                    Approximate
      Gross Processing Capacity  (MMcf/d)
                                    2008
                                      Approximate
                                      Gross
      Inlet
                                      Throughput
                                      Volume
                                      (MMcf/d)
                                    2008
                                      Approximate
                                      Gross
      NGL
                                      Production
                                      (MBbl/d)
                                    Process
                                      Type
      (3)North TexasSystemChico (1)
                                    Wise, TX
                                    265
                                    
                                    
                                    CryoShackelford
                                    Shackelford,TX
                                    13
                                    
                                    
                                    CryoArea Total
                                    278
                                    162.8
                                    19.0SAOU SystemMertzon
                                    Irion, TX
                                    48
                                    
                                    
                                    CryoSterling
                                    Sterling, TX
                                    62
                                    
                                    
                                    CryoConger (2)
                                    Sterling, TX
                                    25
                                    
                                    
                                    CryoArea Total
                                    135
                                    90.3
                                    14.1LOU SystemGillis (1)
                                    Calcasieu,LA
                                    180
                                    
                                    
                                    CryoAcadia
                                    Acadia, LA
                                    80
                                    
                                    
                                    CryoArea Total
                                    260
                                    168.1
                                    9.0





_____________





(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.


(3)
            Cryo
      — Cryogenic Expander.





The
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 5,700 square
miles, that gather wellhead natural gas for the Chico and Shackelford natural
gas processing facilities. During 2008, the North Texas System gathered
approximately 169 MMcf/d of natural gas.





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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 via a
high-pressure 32-mile, 10-inch diameter pipeline, called theInterconnect
Pipeline, 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 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.Our produced NGL is primarily shipped via pipeline to Targa’s Mont
Belvieu facility for fractionation.  Residue gas and NGL are shipped via
several interstate and intrastate natural gas pipelines.





The
SAOU System





Covering
portions of 10 counties and approximately 4,000 square miles in West Texas, the
SAOU System includes approximately 1,350 miles of pipeline in the Permian
Basin that deliver wellhead natural gas to the Mertzon, Sterling and Conger
processing plants. During 2008, the system gathered approximately 99 MMcf/d
of natural gas, including approximately 6 MMcf/d purchased from a third party
gatherer.





Gathering.The SAOU System is
connected to numerous producing wells and/or central delivery points. The system
has approximately 850 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. NGL produced by the SAOU
system are primarily shipped via pipeline to Targa’s Mont Belvieu facility for
fractionation.  Residue gas and NGL are shipped via several interstate and
intrastate pipelines.





The
LOU System





The LOU
System consists of approximately 850 miles of gathering system pipelines,
covering approximately 3,800 square miles in Southwest Louisiana. During
2008, the system gathered approximately 178 MMcf/d of natural gas,
including approximately 53 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. The residue gas produced from the processing plants has direct access
to the Lake Charles industrial market through the system’s intrastate pipeline
system. This intrastate system has the ability to deliver natural gas to
industrial users and electric utilities in the Lake Charles area through both
medium pressure and high pressure pipelines.





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The
Combined Systems





Our
aggregate gas supply contract profile for 2008 on a volume basis was
approximately 77% percent-of-proceeds contracts, 20% wellhead purchase/keep
whole contracts, 2% fee-based contracts and 1% hybrid contracts. Substantially
all of the wellhead and keep-whole contracts are associated with the portion of
the LOU System’s supply comprising processable gas purchased from other pipeline
systems, typically under short term contracts. The LOU System’s industrial
customers can readily accept richer (higher Btu) gas, thereby providing the
system with operational and commercial flexibility to reject or bypass NGLs if
unexpected operating conditions occur or if NGLs are more valuable as natural
gas. The above factors mitigate the commodity price risk typically associated
with wellhead purchase or keep-whole contracts.





Our
largest natural gas supplier for 2008 was Crosstex Energy (“Crosstex”), a gas
gatherer who accounted for approximately 12% of our supply, which sells gas to
us on a spot basis. In addition, purchases from ConocoPhillips accounted for
approximately 11% of our combined gathering volumes in 2008. The loss of all or
even a portion of the natural gas volumes supplied by these customers or the
extension or replacement of these 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.





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, 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 Midstream”), Devon
Energy Corp, Enbridge Inc., GulfSouth Pipeline Company, LP, Hanlan Gas
Processing, Ltd., J W Operating Company, Louisiana Intrastate Gas and several
interstate pipeline companies.  Some of our competitors have greater
financial resources than we possess.





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 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.





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Section
1(b) of the Natural Gas Act of 1938 (“NGA”), exempts natural gas gathering
facilities from regulation as a natural gas company by the Federal Energy
Regulatory Commission (“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 servicesAdditional 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 below the discussion of “Other
Federal Laws and Regulations 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-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, or 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 FERC regulation. On November 20, 2008, FERC issued a Notice
of Inquiry (“NOI”) seeking comment on whether it should impose 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, or
NGPA.  If FERC issues a proposed rulemaking based on the NOI, 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 determined whether a
rulemaking proceeding is necessary and we cannot predict what, if any, rules
FERC will propose as a result of its inquiry or the ultimate impact of any such
regulatory changes to our Hinshaw pipeline.





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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, butane and natural
gasoline) out of our fractionator to and from Targa-owned storage, to other
third party facilities 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. Starting May 1, 2009, we 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
below the discussion of “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 (the “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, 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 rateregulation 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 below the discussion of “Other Federal
Laws and Regulations Affecting Our Industry – Energy Policy Act of 2005.”
Starting May 1, 2009, we may be 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
below the discussion “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.


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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.”





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 the 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 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 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
Market Transparency Rules





In 2007,
FERC issued a final rule on the annual natural gas transaction reporting
requirements, as amended by subsequent orders on rehearing (“Order 704”). Under
Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu 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 million MMBtu of gas over the previous three (3) 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 per day. Requests for clarification and
rehearing of Order 720 have been filed at FERC and a decision on those requests
is pending.





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 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.





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 TABLE OF CONTENTS


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 Systems”. 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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 TABLE OF CONTENTS


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.




Global
Warming and Climate Control




In
response to concerns suggesting that emissions of certain gases, commonly
referred to as “greenhouse gases” (including carbon dioxide (“CO2”) and
methane), are contributing to the warming of the Earth’s atmosphere, 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 greenhouse gases, 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 gas processing
plants, to acquire and surrender emission allowances. Depending on the
particular program, we could be required to purchase and surrender allowances,
either for greenhouse gas emissions resulting from our operations (e.g.,
compressor stations) or from combustion of fuels (e.g., natural gas or 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 greenhouse
gas 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.




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 TABLE OF CONTENTS


Also, as
a result of the U.S. Supreme Court’s decision in 2007 in Massachusetts, et al.
v. EPA, the EPA may regulate greenhouse gas emissions from mobile sources such
as cars and trucks even if Congress does not adopt new legislation specifically
addressing emissions of greenhouse gases. The Court’s holding in Massachusetts
that greenhouse gases including CO2 fall under
the federal Clean Air Act’s definition of “air pollutant” may also result in
future regulation of CO2 and other
greenhouse gas emissions from stationary sources. In July 2008, EPA released an
“Advance Notice of Proposed Rulemaking” regarding possible future regulation of
greenhouse gas emissions under the Clean Air Act, in response to the Supreme
Court's decision in Massachusetts. In the notice,
EPA evaluated the potential regulation of greenhouse gases under the Clean Air
Act and other potential methods of regulating greenhouse gases. Although the
notice did not propose any specific, new regulatory requirements for greenhouse
gases, it indicates that federal regulation of greenhouse gas emissions could
occur in the near future even if Congress does not adopt new legislation
specifically addressing emissions of greenhouse gases. Although it is not
possible at this time to predict how legislation or new regulations that may be
adopted to address greenhouse gas emissions would impact our business, any such
new federal or state 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 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.




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Pipeline
Safety




The
pipelines we use to gather and transport natural gas and transport NGLs are
subject to regulation by the United States Department of Transportation, or the
DOT, under the Natural Gas Pipeline Safety Act of 1968, as amended, or 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 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 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”). 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 $0.4 million for years 2009 through
2011 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, in September 2008, PHMSA issued a proposed 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 proposed rule would require 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. While we do not
anticipate that the rule, as proposed, will result in substantial costs with
respect to our operations, the rule is not yet finalized and thus we cannot
provide assurance on how significant an impact the rule ultimately will have on
our operations, once it is adopted.




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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.




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





To carry
out its operations, Targa employs approximately 950 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. We do not have any employees.





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, 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 (1) the SEC at the SEC’s Public Reference Room at 100
F Street, N.E., Washington, D.C. 20549, (2) by calling 1-800-SEC-0330 and (3) 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
addition, 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 by approximately
$10.0 million. 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, 2008 we had approximately $696.8 million of total
indebtedness outstanding,approximately $9.7 million of letters of credit outstanding and
$342.5 million of additional borrowing capacity under our credit facility. In
October 2008, one of the lenders under our credit facility, Lehman Bank,
defaulted on a borrowing request. As a result, we believe the total commitments
under the credit facility have been effectively reduced by approximately
$10.0 million. Our credit facility allows us to request increases in the
commitments under the credit facility of up to $150 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;


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





·
            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 and
subordinated units.





Our
operations can be affected by the level of natural gas and NGL prices and the
relationship between these prices. The prices of 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 fluctuate 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.





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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, 2008, our percent-of-proceeds arrangements
accounted for approximately 77% 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
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 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 NGL
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.





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Our
hedging activities may not be effective in reducing the variability of our cash
flows and may, in certain circumstances, increase the variability of our cash
flows. Moreover, our hedges may not fully protect us against volatility in basis
differentials. Finally, the percentage of our 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 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, resulting in a reduction of
our liquidity. 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
depend on two natural gas producers for a significant portion of our supply of
natural gas. The loss of these customers or the replacement of their contracts
on less favorable terms could result in a decline in our volumes, revenues and
cash available for distribution.





Our
largest natural gas supplier for 2008 was Crosstex, a gas gatherer who accounted
for approximately 12% of our supply, which sells gas to us on a spot basis. In
addition, purchases from ConocoPhillips accounted for approximately 11% of our
combined gathering volumes in 2008. The loss of all or even a portion of the
natural gas volumes supplied by these customers or the extension or replacement
of these 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 can not 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.





Our
acquisitions involve numerous risks, including:





·
            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;


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





·
            the
      failure to realize expected profitability or
  growth;





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





·
            coordinating
      geographically disparate organizations, systems and
      facilities.





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.





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, NGLs and
high-pressure condensate for a term of 15 years and (ii) substantially
all of the SAOU and LOU Systems’ natural gas for a term of 15 years and
NGLs for a term of one year. 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. 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
25, 2009 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.


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Typically
do not obtain independent evaluations of natural gas reserves dedicated to our
gathering pipeline systems; therefore, volumes of natural gas on our systems in
the future could be less than we anticipate.





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.





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.


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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 ability to make
distributions to our unitholders.





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. The insurance market conditions have worsened as a result of the
losses sustained from Hurricanes Gustav and Ike in September 2008. As a result,
we expect to experience further increases in deductibles and premiums and
further reductions in coverage and limits, with some coverages unavailable at
any cost.







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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, 2008, we had
approximately $487.8 million of debt outstanding under our credit facility
at variable interest rates. 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.”





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 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.”





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.





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.





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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) the federal Resource Conservation
and Recovery Act (“RCRA”) and comparable state laws that impose requirements for
the handling, storage, treatment or disposal of solid and hazardous waste from
our facilities, (3) the federal Comprehensive Environmental Response,
Compensation and Liability Act of 1980 (“CERCLA”) also known as “Superfund,” 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
disposal and (4) the Federal Water Pollution Control Act (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 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 and other petroleum
products, air emissions and water discharges related to our operations and
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, the possibility
exists that stricter laws, regulations or enforcement policies could
significantly increase our operational or compliance costs and the cost of any
remediation that may become necessary. In particular, we may incur expenditures
in order to attain or maintain compliance with legal requirements governing
emissions of air pollutants from our facilities. We may not be able to recover
all or any of these costs from insurance. For further information on
environmental matters, see “Item 1. Business— Environmental, Health and Safety
Matters” for additional information on environmental matters.





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.





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
(“Order 720”) requiring major non-interstate pipelines, defined as certain
non-interstate pipelines delivering, on an annual basis, more than an average of
50 million MMBtus 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 per day.


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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 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”.





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, DOT,
through the PHMSA, has adopted regulations requiring pipeline operators to
develop integrity management programs for transmission pipelines 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.





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In
addition, states have adopted regulations similar to existing U.S. DOT
regulations for intrastate gathering and transmission lines. We currently
estimate that we will incur an aggregate cost of approximately $1.2 million
between 2009 and 2011 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 or 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.





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.





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





·
            inaccurate
      assumptions about volumes, revenues and costs, including
      synergies;





·
            an
      inability to integrate successfully the businesses we
    acquire;





·
            the
      assumption of unknown liabilities;





·
            limitations
      on rights to indemnity from the
seller;





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





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


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·
            unforeseen
      difficulties operating in new product areas or new geographic areas;
      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.





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.





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
and subordinated units depends primarily on our cash flow and not solely on
profitability. Consequently, even if we are profitable, we may not be able to
make cash distributions to holders of our common units and subordinated
units.





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.


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 TABLE OF CONTENTS





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.





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 and subordinated unit per complete quarter or $2.07 per unit
per year, we will require available cash of approximately $26.4 million per
quarter or $105.4 million per year, based on common units and subordinated
units outstanding as of December 31, 2008. 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;






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 TABLE OF CONTENTS





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





·
            restrictions
      on distributions contained in our debt agreements;
  and





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





Targa
controls our general partner, which has sole responsibility for conducting our
business and managing our operations. Targa has conflicts of interest with us
and may favor its own interests to your detriment.





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;





·
            our
      general partner is allowed to take into account the interests of parties
      other than us, such as Targa or its owners, including Warburg Pincus, in
      resolving conflicts of interest;
and





·
            Targa
      is not limited in its ability to compete with us and is under no
      obligation to offer assets to us.





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





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.





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;


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·
            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.





Targa
is not limited in its ability to compete with 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.





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. 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.





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Removal
of our general partner without its consent will dilute and adversely affect our
common unitholders.





If our
general partner is removed without cause during the subordination period and
units held by our general partner and its affiliates are not voted in favor of
that removal, all remaining subordinated units will automatically convert into
common units and any existing arrearages on our common units will be
extinguished. A removal of our general partner under these circumstances would
adversely affect our common units by prematurely eliminating their distribution
and liquidation preference over our subordinated units, which would otherwise
have continued until we had met certain distribution and performance tests.
Cause is narrowly defined to mean that a court of competent jurisdiction has
entered a final, non-appealable judgment finding the general partner liable for
actual fraud or willful or wanton misconduct in its capacity as our general
partner. Cause does not include most cases of charges of poor management of the
business, so the removal of the general partner because of the unitholder’s
dissatisfaction with our general partner’s performance in managing our
partnership will most likely result in the termination of the subordination
period and conversion of all subordinated units to common units.





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;





·
            because
      a lower percentage of total outstanding units will be subordinated units,
      the risk that a shortfall in the payment of the minimum quarterly
      distribution will be borne by our common unitholders will
      increase;





·
            the
      ratio of taxable income to distributions may
  increase;





·
            the
      relative voting strength of each previously outstanding unit may be
      diminished; and





·
            the
      market price of the common units may
decline.





Affiliates
of our general partner may sell common units in the public markets, which sales
could have an adverse impact on the trading price of the common
units.





Management
of our general partner and Targa beneficially hold 292,252 common units and
11,528,231 subordinated units. All of the subordinated units will convert into
common units at the end of the subordination period and may convert earlier. 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, at a time when there are no subordinated units
outstanding and 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.





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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 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.
At the end of the subordination period, assuming no additional issuances of
common units, our general partner and its affiliates will own approximately
24.5% of our aggregate outstanding common units.





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





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 fromthe IRS with respect to our
treatment as a partnership for federal income tax purposes. We have requested a
ruling from the IRS with respect to the qualifying nature of the income earned
as a result of a purchase of our debt at a discount upon which, if granted, we
may rely with respect to such income. There can be no assurance that the IRS
will provide such a favorable ruling. However, any income earned as a result of
a purchase or our debt at a discount plus any other non-qualifying income we
earned in 2008 is less than 10% of our total gross income.





Although
we do not believe based upon our current operations that we are 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.


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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, members of Congress have considered substantive changes to the
existing U.S. tax laws that would have affected certain publicly traded
partnerships. Although the legislation considered would not have appeared to
affect our tax treatment, 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.





Our
partnership agreement provides that if a law is enacted or existing law is
modified or interpreted in a manner that subjects us to taxation as a
corporation or otherwise subjects us to entity-level taxation for federal, state
or local income tax purposes, the minimum quarterly distribution amount and the
target distribution amounts may be adjusted to reflect the impact of that law on
us.





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. If the IRS were to challenge this method or new
Treasury regulations were issued, we may be required to change the allocation of
items of income, gain, loss and deduction among our unitholders.





If
the IRS contests the federal income tax positions we take, the market for our
common units may be adversely affected and the cost of any contest will reduce
our cash available for distribution to you.





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.





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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.
Prior distributions to you in excess of the total net taxable income you were
allocated for a common unit, which decreased your tax basis in that common unit,
will, in effect, become taxable income to you if the common unit is sold at a
price greater than your tax basis in that common unit, 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
(known as IRAs), other retirement plans and non-United States persons raises
issues unique to them. For example, virtually all of our 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 without the benefit of additional
deductions. 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.





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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. 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 could 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.





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 do 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 requirements. We own
assets and conduct business in the States of Texas and Louisiana. Currently,
Texas does not impose a personal income tax on individuals. As we make
acquisitions or expand our business, we may own assets or do 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








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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 (“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 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 and the appeal
is pending before the 14th Court
of Appeals in Houston, Texas.  We are contesting WTG’s appeal, but can
give no assurances regarding the outcome of the proceeding. 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.Submission of
Mattersto a Vote of Security Holders





None


40
 TABLE OF CONTENTS


PART II





Item
5. Market for
Registrant’sCommon Equity, Related Unitholder Matters and Issuer Purchases
of Equity Securities





Market
Information





Our
common units have been listed on The NASDAQ Stock Market LLC (“NASDAQ”) under
the symbol “NGLS” since February 9, 2007. Prior to February 9, 2007, our equity
securities were not listed on any exchange or traded on any public trading
market. 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 February 14, 2007 through December 31,
2008.








Distribution
                  
                  
                  Distributionper
      Common
                  
                  
                  per
      SubordinatedQuarter Ended
                  
                  High
                  
                  
                  Low
                  
                  
                  Unit
                  
                  
                  UnitDecember
      31, 2008
                  
                  $
                  17.11
                  
                  
                  $
                  6.04
                  
                  
                  $
                  0.51750
                  
                  
                  $
                  0.51750September
      30, 2008
                  
                  
                  24.46
                  
                  
                  
                  15.18
                  
                  
                  
                  0.51750
                  
                  
                  
                  0.51750June
      30, 2008
                  
                  
                  27.08
                  
                  
                  
                  22.93
                  
                  
                  
                  0.51250
                  
                  
                  
                  0.51250March
      31, 2008
                  
                  
                  29.54
                  
                  
                  
                  20.88
                  
                  
                  
                  0.41750
                  
                  
                  
                  0.41750December
      31, 2007
                  
                  
                  29.84
                  
                  
                  
                  25.10
                  
                  
                  
                  0.39750
                  
                  
                  
                  0.39750September
      30, 2007
                  
                  
                  35.00
                  
                  
                  
                  24.39
                  
                  
                  
                  0.33750
                  
                  
                  
                  0.33750June
      30, 2007
                  
                  
                  35.28
                  
                  
                  
                  27.70
                  
                  
                  
                  0.33750
                  
                  
                  
                  0.33750March
      31, 2007
                  
                  
                  29.30
                  
                  
                  
                  22.75
                  
                  
                  
                  0.16875
                  
                  
                  
                  0.16875








As of
February 4, 2009, there were approximately 57 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. We have also issued 11,528,231 subordinated units,
for which there is no established public trading market. The subordinated units
are held by affiliates of Targa Resources GP LLC, our general partner. Our
general partner and its affiliates will receive a quarterly distribution on
these units only after sufficient funds have been paid to the common units.
There is no established trading market for the 943,108 general partner units
held by our general partner.





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.





41
 TABLE OF CONTENTS


Minimum Quarterly Distribution.We intend to make cash distributions to the holders of common units and
subordinated 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 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.





General Partner Interest.Our
general partner is currently entitled to 2% of all quarterly distributions that
we make prior to our liquidation. This general partner interest is represented
by 943,108 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 $0.5063 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





On
October 10, 2008, the Board of Directors of our general partner approved a
program for us to repurchase up to $50 million in value of our common units from
time to time through December 31, 2009 in open market transactions, including
block purchases or in privately negotiated transactions. The unit repurchase
program authorizes us to make repurchases on a discretionary basis as determined
by our management subject to market conditions, applicable legal requirements,
available liquidity and other appropriate factors as determined by such
officers. The unit repurchase program does not include specific price targets or
timetables and may be modified or suspended at any time and could be terminated
prior to completion. Repurchased common units will be cancelled and current
payments on our incentive distribution rights will decrease.





There
have been no repurchases of our common units under this program.





42
 TABLE OF CONTENTS


Item 6.Selected
Financial Data





SELECTED
FINANCIAL AND OPERATING DATA





Our
historical results include the historical results of the SAOU and LOU Systems
(acquired by Targa effective April 16, 2004) for 2008, 2007 and 2006;
and the historical results of the North Texas System (acquired by Targa
effective November 1, 2005) subsequent to October 31,
2005.





The
information contained herein should be read together with and is qualified in
its entirety by reference to, the historical combined financial statements and
the accompanying notes included elsewhere in this Annual Report. See “Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of
Operations” for a discussion of factors that affect the comparability of the
information reflected in the selected financial and operating data.





In the
following tables, our predecessor entity comprises the net assets of the SAOU
and LOU Systems as these were the first assets acquired by Targa on April 16,
2004. The financial and operating data as of and for the year ended December 31,
2004 are derived from the audited consolidated financial statements of Targa.
Targa’s consolidated financial results for 2004 includes the results of
operations for the eight and a half month period commencing with its April 16,
2004 acquisition of the predecessor business from ConocoPhillips. The selected
combined financial and operating data of the predecessor for the three and a
half months ended April 15, 2004 are derived from the audited financial
statements of the predecessor business.





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





Targa Resources Partners
      LP
                                
                                
                                PredecessorYear Ended December 31,
                                March
      12 (Inception) through December 31,
                                
                                
                                106-Day
      Period Ended April 15,2008
                                2007
                                2006
                                2005
                                2004
                                
                                
                                2004(In
      millions, except operating and price data)Statement
      of Operations data:Revenues
                                $2,074.1
                                $1,661.5
                                $1,738.5
                                $1,172.5
                                $602.6
                                
                                
                                $232.8Costs
      and expenses:Product
      purchases
                                1,803.0
                                1,406.8
                                1,517.7
                                1,061.7
                                544.9
                                
                                
                                212.3Operating
      expenses
                                55.3
                                50.9
                                49.1
                                24.4
                                15.3
                                
                                
                                7.9Depreciation
      and amortization expense
                                74.3
                                71.8
                                69.9
                                23.1
                                10.4
                                
                                
                                3.8General
      and administrative expense
                                22.4
                                18.9
                                16.1
                                16.7
                                11.1
                                
                                
                                0.8Other
                                0.1
                                -
                                -
                                -
                                -
                                
                                
                                1.4Gain
      on sale of assets
                                (0.1)
                                (0.3)
                                -
                                -
                                -
                                
                                
                                -Total
      costs and expenses
                                1,955.0
                                1,548.1
                                1,652.8
                                1,125.9
                                581.7
                                
                                
                                226.2Income
      from operations
                                119.1
                                113.4
                                85.7
                                46.6
                                20.9
                                
                                
                                6.6Other
      income (expense):Interest
      expense, net
                                (38.3)
                                (22.0)
                                -
                                -
                                -
                                
                                
                                -Interest
      expense, allocated from Parent
                                -
                                (19.4)
                                (88.0)
                                (21.2)
                                (6.1)
                                
                                
                                -Gain
      on debt extinguishment
                                13.1
                                -
                                -
                                (3.7)
                                -
                                
                                
                                -Gain
      (loss) related to derivatives
                                (1.0)
                                (30.2)
                                16.8
                                (12.0)
                                1.3
                                
                                
                                -Income
      before income taxes
                                92.9
                                41.8
                                14.5
                                9.7
                                16.1
                                
                                
                                6.6Deferred
      income tax expense (1)
                                (1.4)
                                (1.5)
                                (2.9)
                                -
                                -
                                
                                
                                (2.6)Net
      income
                                $91.5
                                $40.3
                                $11.6
                                $9.7
                                $16.1
                                
                                
                                $4.0Less:Net
      income attributable to predecessor operations
                                -
                                12.2Net
      income allocable to partners
                                91.5
                                28.1General
      partner interest in net income
                                7.0
                                0.6Net
      income available to common and subordinated unitholders
                                $84.5
                                $27.5Net
      income per limited partner unit - basic
                                $1.83
                                $0.81Net
      income per limited partner unit - diluted
                                $1.83
                                $0.81Cash
      distributions declared per unit
                                $1.97
                                $1.24Financial
      and Operating data:Financial
      data:Operating
      margin (2)
                                $215.8
                                $203.8
                                $171.7
                                $86.4
                                $42.4
                                
                                
                                $12.6Adjusted
      EBITDA (3)
                                $228.9
                                $185.8
                                $154.1
                                $66.0
                                $31.3
                                
                                
                                $11.8Distributable
      cash flow (4)
                                $152.8
                                $124.1
                                $57.5
                                $43.3
                                N/A
                                
                                
                                N/AOperating
      data:Gathering
      throughput, MMcf/d (5)
                                445.8
                                452.0
                                433.8
                                302.4Plant
      natural gas inlet, MMcf/d (6)(7)
                                421.2
                                429.2
                                419.6
                                253.6Gross
      NGL production, MBbl/d
                                42.0
                                42.6
                                42.4
                                23.5Natural
      gas sales, BBtu/d (7)
                                415.6
                                410.2
                                489.4
                                259.3NGL
      sales, MBbl/d
                                37.3
                                36.4
                                36.0
                                22.0Condensate
      sales, MBbl/d
                                3.6
                                3.6
                                3.3
                                1.3Average
      realized prices (8):Natural
      gas, $/MMBtu
                                8.45
                                6.60
                                6.62
                                9.36NGL,
      $/gal
                                1.17
                                1.03
                                0.85
                                0.77Condensate,
      $/Bbl
                                82.52
                                65.63
                                59.87
                                58.96







43
 TABLE OF CONTENTS




Balance
      Sheet Data (at year end):Property
      plant and equipment, net
                          $1,244.3
                          $1,259.6
                          $1,288.6
                          $1,325.9
                          $237.6
                          
                          
                          $266.0Total
      assets
                          1,580.9
                          1,480.0
                          1,416.4
                          1,500.0
                          323.4
                          
                          
                          288.8Long-term
      allocated debt, less current maturities
                          -
                          -
                          1,047.3
                          1,053.3
                          103.0
                          
                          
                          -Long-term
      debt, less current maturities
                          696.8
                          626.3
                          -
                          -
                          -
                          
                          
                          -Partners'
      capital/Net parent equity
                          762.4
                          614.2
                          245.9
                          281.2
                          139.2
                          
                          
                          170.9Cash
      Flow Data:Net
      cash provided by (used in):
                          
                          
                          
                          10.5
                          28.2
                          
                          
                          11.5Operating
      activities
                          95.2
                          270.5
                          124.4
                          (6.8)
                          (2.9)
                          
                          
                          (1.2)Investing
      activities
                          (51.0)
                          (40.7)
                          (32.9)
                          (3.7)
                          (25.4)
                          
                          
                          (10.3)Financing
      activities
                          (13.5)
                          (178.8)
                          (91.5)
                          -
                          -
                          
                          
                          -
 
 ______________





(1)
            In
      May 2006, Texas adopted a margin tax consisting of a 1% tax on the amount
      by which total revenue exceeds cost of goods sold, as apportioned to
      Texas. The amount presented represents our estimated liability for this
      tax.(2)
            Operating
      margin is total operating revenues less product purchases and operating
      expense. 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.”(3)
            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.”(4)
            Distributable
      Cash Flow is net income plus depreciation and amortization and deferred
      taxes, adjusted for losses/(gains) on mark-to-market derivative contracts
      and early extinguishment of debt, 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.”(5)
            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.(6)
            Plant
      natural gas inlet represents the volume of natural gas passing through the
      meter located at the inlet of a natural gas processing
    plant.(7)
            Plant
      inlet volumes include producer take-in-kind, while natural gas sales
      exclude producer take-in-kind volumes.(8)
            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.





44
 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. Our non-GAAP financial measure of 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.








Targa Resources Partners LP
                          
                          
                          PredecessorYear Ended December 31,
                          March
      12 (Inception) through December 31,
                          
                          
                          106-Day
      Period Ended April 15,2008
                          2007
                          2006
                          2005
                          2004
                          
                          
                          2004(In
      millions)Reconciliation
      of net cash provided by operating activities to Adjusted
      EBITDA:Net
      cash provided by operating activities
                          $95.2
                          $270.5
                          $124.4
                          $10.5
                          $28.2
                          
                          
                          $11.5Allocated
      interest expense from parent (1)
                          -
                          18.5
                          81.8
                          16.5
                          5.2
                          
                          
                          -Interest
      expense, net (1)
                          36.2
                          21.1
                          -
                          -
                          -
                          
                          
                          -Gain
      on debt extinguishment
                          13.1
                          -
                          -
                          (3.7)
                          -
                          
                          
                          -Early
      termination of commodity derivatives
                          87.4
                          -
                          -
                          -
                          -
                          
                          
                          -Other
                          (0.5)
                          (0.1)
                          (0.4)
                          3.6
                          -
                          
                          
                          4.0Changes
      in operating assets and liabilities which used (provided)
      cash:Accounts
      receivable and other assets
                          (64.3)
                          (88.8)
                          (80.9)
                          63.8
                          77.5
                          
                          
                          (25.1)Accounts
      payable and other liabilities
                          61.8
                          (35.4)
                          29.2
                          (24.7)
                          (79.6)
                          
                          
                          21.4Adjusted
      EBITDA
                          $228.9
                          $185.8
                          $154.1
                          $66.0
                          $31.3
                          
                          
                          $11.8Reconciliation
      of net income to Adjusted EBITDA:Net
      income
                          $91.5
                          $40.3
                          $11.6
                          $9.7
                          $16.1
                          
                          
                          $4.0Add:Allocated
      interest expense, net
                          -
                          19.4
                          88.0
                          21.2
                          6.1
                          
                          
                          -Interest
      expense, net
                          38.3
                          22.0
                          -
                          -
                          -
                          
                          
                          -Deferred
      income tax expense
                          1.4
                          1.5
                          2.9
                          -
                          -
                          
                          
                          2.6Taxes
      other than income taxes
                          -
                          -
                          -
                          -
                          -
                          
                          
                          1.4Depreciation
      and amortization expense
                          74.3
                          71.8
                          69.9
                          23.1
                          10.4
                          
                          
                          3.8Non-cash
      (income) loss related to derivatives
                          23.4
                          30.8
                          (18.3)
                          12.0
                          (1.3)
                          
                          
                          -Adjusted
      EBITDA
                          $228.9
                          $185.8
                          $154.1
                          $66.0
                          $31.3
                          
                          
                          $11.8


______________


45
 TABLE OF CONTENTS








(1)
            Net
      of amortization of debt issuance costs of $2.1 million,
      $1.8 million and $6.2 million for 2008, 2007 and
      2006.





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 and trend analysis. Based on this monthly analysis, management takes
appropriate action to maintain positive trends or to reverse negative trends.
Management uses operating margin as an important performance measure of the core
profitability of our operations.





The GAAP
measure most directly comparable to operating margin is net income. Our non-GAAP
financial measure of 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.





Targa Resources Partners LP
                      
                      
                      PredecessorYear Ended December 31,
                      March
      12 (Inception) through December 31,
                      
                      
                      106-Day
      Period Ended April 15,2008
                      2007
                      2006
                      2005
                      2004
                      
                      
                      2004(In
      millions)Reconciliation
      of net income to operating margin:Net
      income
                      $91.5
                      $40.3
                      $11.6
                      $9.7
                      $16.1
                      
                      
                      $4.0Add:Depreciation
      and amortization expense
                      74.3
                      71.8
                      69.9
                      23.1
                      10.4
                      
                      
                      3.8Deferred
      income tax expense
                      1.4
                      1.5
                      2.9
                      -
                      -
                      
                      
                      2.6Allocated
      interest expense, net
                      -
                      19.4
                      88.0
                      21.2
                      6.1
                      
                      
                      -Interest
      expense, net
                      38.3
                      22.0
                      -
                      -
                      -
                      
                      
                      -Gain
      on debt extinguishment
                      (13.1)
                      -
                      -
                      3.7
                      -
                      
                      
                      -(Gain)
      loss on mark-to-market derivatives
                      1.0
                      30.2
                      (16.8)
                      12.0
                      (1.3)
                      
                      
                      -General
      and administrative and other expense
                      22.4
                      18.6
                      16.1
                      16.7
                      11.1
                      
                      
                      2.2Operating
      margin (1)
                      $215.8
                      $203.8
                      $171.7
                      $86.4
                      $42.4
                      
                      
                      $12.6





______________


46
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(1)
            Includes
      non-cash charges related to commodity hedges of $1.0 million, $30.2
      million and $(16.8) million for 2008, 2007and
  2006.





Distributable Cash Flow.
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 non-GAAP 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. Our
non-GAAP measure of 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 31,2008
                  
                  
                  2007
                  
                  
                  2006
                  
                  
                  2005Reconciliation
      of net income
                  
                  (In
      millions)to
      "distributable cash flow":Net
      income
                  
                  $
                  91.5
                  
                  
                  $
                  40.3
                  
                  
                  $
                  11.6
                  
                  
                  $
                  9.7Depreciation
      and amortization expense
                  
                  
                  74.3
                  
                  
                  
                  71.8
                  
                  
                  
                  69.9
                  
                  
                  
                  23.1Deferred
      income tax expense
                  
                  
                  1.4
                  
                  
                  
                  1.5
                  
                  
                  
                  2.9
                  
                  
                  
                  -Amortization
      in interest expense
                  
                  
                  2.1
                  
                  
                  
                  1.8
                  
                  
                  
                  6.2
                  
                  
                  
                  4.7Gain
      on debt extinguishment
                  
                  
                  (13.1
                  )
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Non-cash
      (gain) loss related to derivatives
                  
                  
                  23.4
                  
                  
                  
                  30.2
                  
                  
                  
                  (16.8
                  )
                  
                  
                  12.0Maintenance
      capital expenditures
                  
                  
                  (26.7
                  )
                  
                  
                  (21.5
                  )
                  
                  
                  (16.3
                  )
                  
                  
                  (6.2
                  )Distributable
      cash flow (1)
                  
                  $
                  152.9
                  
                  
                  $
                  124.1
                  
                  
                  $
                  57.5
                  
                  
                  $
                  43.3





____________





(1)
            Distributable
      cash flow for 2007, 2006 and 2005 reflect allocated interest from parent
      of $19.4 million, $88.0 million and $21.2
    million.








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





On
February 14, 2007, Targa contributed its ownership interests in the North
Texas System to us. On October 24, 2007, we acquired Targa’s ownership
interests in the SAOU System and the LOU System. As required by Statement of
Financial Accounting Standards (“SFAS”) 141, we accounted for these transactions
as transfers of net assets between entities under common control. For
combinations of entities under common control, the purchase cost provisions (as
they relate to purchase business combinations involving unrelated entities) of
SFAS 141 explicitly do not apply; instead the method of accounting
prescribed by SFAS 141 for such transfers is similar to the
pooling-of-interests method of accounting. Under this method, the carrying
amount of net assets recognized in the balance sheets of each combining entity
are carried forward to the balance sheet of the combined entity and no other
assets or liabilities are recognized as a result of the combination (that is, no
recognition is made for a purchase premium or discount representing any
difference between the cash consideration paid and the book value of the net
assets acquired).





In
connection with our IPO, the North Texas System was presented as our predecessor
entity. As a result of our October 2007 acquisition of the SAOU and LOU Systems,
the predecessor entity for us is now considered to be the net assets of the SAOU
and LOU Systems as these were the first assets acquired by Targa on
April 16, 2004. Therefore, subsequent to the contribution of the North
Texas System from Targa on February 14, 2007, we recognized the assets and
liabilities of the North Texas System contributed to us at their carrying
amounts (historical cost) in the accounts of the SAOU and LOU Systems (the
predecessor entity) at the date of transfer. The accounting treatment for
combinations of entities under common control is consistent with the concept of
poolings as combinations of common shareholder (or unitholder)
interests.





In
addition to requiring that assets and liabilities be carried forward at
historical costs, SFAS 141 also prescribes that for transfers of net assets
between entities under common control, all income statements presented be
combined as of the date of common control. Accordingly, our historical results
include the historical results of the SAOU and LOU Systems (acquired by Targa
effective April 16, 2004) for 2008, 2007 and 2006; and the historical
results of the North Texas System (acquired by Targa effective November 1,
2005) subsequent to October 31, 2005.





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





Overview





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
currently operate in the Fort Worth Basin in North Texas, the Permian Basin
in West Texas and in Southwest Louisiana.





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 are publicly traded on the NASDAQ Stock Market LLC under the symbol
“NGLS.”





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,
which we refer to as throughput volume. Throughput volumes and capacity
utilization rates 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.





Contract Mix.Our processing
contract arrangements can have a significant impact on our profitability. We
generate revenue based on the contractual arrangements we have with our producer
customers. These arrangements can be in many forms which vary in the amount of
commodity price risk they carry. Substantially all of our revenues are generated
under percent-of-proceeds arrangements pursuant to which we receive a portion of
the natural gas and/or NGLs as payment for services. Below is a table
summarizing our average contract mix for 2008, including the potential impacts
of changes in commodity prices on operating margins:


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Contract Type
                      Percent
      of
                        Throughput
                      Impact of Commodity
  PricesPercent-of-Proceeds
                      77%
                      Decreases
      in natural gas and/or NGL prices generate decreases in operating
      margin.Wellhead
      Purchases/Keep Whole
                      20%
                      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
                      2%
                      No
      direct impact from commodity price
movements.





Actual
contract terms are based upon a variety of factors, including natural gas
quality, geographic location and 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.





We
attempt to mitigate the price risk associated with our contract mix 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 2009 through 2012
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. Prior to the contribution of the assets of the North Texas
System to us and the acquisition of the assets from the SAOU and LOU Systems by
us from Targa, general and administrative expenses were allocated from Targa to
the North Texas, SAOU and LOU Systems in accordance with the general and
administrative expenses allocation policies of Targa. On February 14, 2007,
we entered into an omnibus agreement with Targa, pursuant to which our allocated
general and administrative expenses related to the North Texas System were
capped at $5.0 million per year for three years, subject to
adjustment.





On
October 24, 2007, we amended and restated our omnibus agreement with Targa
(the “Omnibus Agreement”). The Omnibus Agreement governs certain relationships
between Targa and us, including:





•
            Targa’s
      obligation to provide certain general and administrative services to
      us;





•
            our
      obligation to reimburse Targa and its affiliates for the provision of
      general and administrative services (a) subject to a cap of
      $5 million (relating solely to the North Texas System) in the first
      year, with increases in the subsequent two years based on a formula
      specified in the Omnibus Agreement and (b) fully allocated as to the
      SAOU and LOU Systems according to Targa’s previously established
      allocation practices;





•
            our
      obligation to reimburse Targa and its affiliates for direct expenses
      incurred on our
behalf; and


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•
            Targa’s
      obligation to indemnify us for certain liabilities and our obligation to
      indemnify Targa for certain
liabilities.





Allocated
general and administrative expenses were $18.2 million, $15.6 million
and $16.1 million for 2008, 2007 and 2006. For a more complete description
of this agreement, see “Item 13. Certain Relationships and Related Transactions,
and Director Independence—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 $4.2 million and
$3.3 million during 2008 and 2007, including one-time expenses associated
with our equity offerings, financing arrangements and acquisitions
were  not subject to the cap contained in the Omnibus Agreement. These
costs 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. These incremental general and administrative expenditures are not
reflected in the historical financial statements of the North Texas, SAOU and
LOU Systems.





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





Affiliate Indebtedness and
Borrowings. Affiliate indebtedness prior to our acquisition of the SAOU
and LOU Systems and the contribution of the North Texas System, consisted of
borrowings incurred by Targa and allocated to us for financial reporting
purposes.





Prior to
Targa’s acquisition of Dynegy’s interest in Dynegy Midstream Services, Limited
Partnership (the “DMS Acquisition”), which included the North Texas System, the
Predecessor Business was financed through borrowings by Targa and reflected
allocated indebtedness on its balance sheet and allocated interest expense on
its income statement. A substantial portion of the DMS Acquisition was also
financed through borrowings by Targa. Following the October 31, 2005 DMS
Acquisition, a significant portion of Targa’s acquisition borrowings were
allocated to the North Texas System, resulting in approximately
$870.1 million of allocated indebtedness and corresponding levels of
interest expense. This indebtedness was incurred by Targa in connection with the
DMS Acquisition and the entity holding the North Texas System provided a
guarantee of this indebtedness. This indebtedness was also secured by a
collateral interest in both the equity of the entity holding the North Texas
System as well as its assets. In connection with our IPO, this guarantee was
terminated, the collateral interest was released and the allocated indebtedness
was retired.





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 (including 2,520,000 common
units sold pursuant to the full exercise by the underwriters of their option to
purchase additional common units), were used to repay approximately
$665.7 million of affiliate indebtedness and the remaining balance of this
indebtedness 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
(approximately $349.2 million after underwriting discount and structuring
fees). The net proceeds from the sale of the 13,500,000 units were used to
pay approximately $2.5 million in expenses associated with the sale of the
common units and $24.2 million to Targa for certain hedge transactions
associated with the SAOU and LOU Systems. We used the net proceeds after
offering expenses and the 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. Targa
debt was guaranteed by the entities that own the SAOU and LOU Systems and was
secured by a collateral interest in both the equity interests of those entities
as well as their underlying assets. In conjunction with our acquisition of the
SAOU and LOU Systems, this guarantee was terminated, the collateral interest was
released and the allocated indebtedness was retired.





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Working Capital Adjustments.Prior to our IPO and 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 Predecessor Business’ respective
parent, 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. Accordingly, the working capital of the Predecessor
Business does not reflect any affiliate accounts receivable for intercompany
commodity sales or 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. Historically, we have relied on internally
generated cash flows for these purposes. Due to the timing of our IPO, a
pro-rated distribution for the first quarter of 2007 of $0.16875 per common and
subordinated unit was paid.





The
following table shows the distributions we declared for the period February 14,
2007 through December 31, 2008.





Distributions Paid
                    
                    
                    DistributionsCommon
                    
                    
                    Subordinated
                    
                    
                    General Partner
                    
                    
                    
                    
                    
                    per
      limitedDate Declared
                    Date Paid
                    
                    Units
                    
                    
                    Units
                    
                    
                    Incentive
                    
                    
                    
                    2
                    %
                    
                    Total
                    
                    
                    partner unit(In
      thousands, except per unit amounts)October
      24, 2008
                    November
      14, 2008
                    
                    $
                    17,934
                    
                    
                    $
                    5,966
                    
                    
                    $
                    1,931
                    
                    
                    $
                    527
                    
                    
                    $
                    26,358
                    
                    
                    $
                    0.51750July
      23, 2008
                    August
      14, 2008
                    
                    
                    17,759
                    
                    
                    
                    5,908
                    
                    
                    
                    1,711
                    
                    
                    
                    518
                    
                    
                    
                    25,896
                    
                    
                    
                    0.51250April
      23, 2008
                    May
      15, 2008
                    
                    
                    14,467
                    
                    
                    
                    4,813
                    
                    
                    
                    208
                    
                    
                    
                    398
                    
                    
                    
                    19,886
                    
                    
                    
                    0.41750January
      23, 2008
                    February
      14, 2008
                    
                    
                    13,768
                    
                    
                    
                    4,582
                    
                    
                    
                    66
                    
                    
                    
                    376
                    
                    
                    
                    18,792
                    
                    
                    
                    0.39750October
      24, 2007
                    November
      14, 2007
                    
                    
                    11,082
                    
                    
                    
                    3,891
                    
                    
                    
                    -
                    
                    
                    
                    305
                    
                    
                    
                    15,278
                    
                    
                    
                    0.33750July
      24, 2007
                    August
      14, 2007
                    
                    
                    6,526
                    
                    
                    
                    3,890
                    
                    
                    
                    -
                    
                    
                    
                    212
                    
                    
                    
                    10,628
                    
                    
                    
                    0.33750April
      23, 2007
                    May
      15, 2007
                    
                    
                    3,263
                    
                    
                    
                    1,945
                    
                    
                    
                    -
                    
                    
                    
                    107
                    
                    
                    
                    5,315
                    
                    
                    
                    0.16875





On
January 23, 2009, we declared a cash distribution of $0.5175 per unit on
our outstanding common and subordinated units. The distribution was paid on
February 13, 2009 to unitholders of record on February 4, 2008, for
the period October 1, 2008 through December 31, 2008. The total
distribution paid was approximately $26.4 million, with approximately
$23.9 million paid to our common unitholders and $0.5 million and
$1.9 million paid to our general partner for its general partner and
incentive distribution interests.





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 natural gas prices
increase and decrease as natural gas prices decrease. 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 2009 which could lead to a decrease in the level of natural gas
production in our areas of operation.




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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. Due to the recent volatility, we are uncertain of what
pricing and market demand for natural gas, NGLs and condensate will be
throughout 2009. The current weak economic conditions have negatively affected
the pricing and market demand for natural gas, NGLs and condensate, which has
caused a reduction in the 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.




Our
Operations





Our
results of operations are determined primarily by the volumes of natural gas
gathered, compressed, treated, processed, moved and sold through our gathering,
processing and pipeline systems; the volumes of NGLs and residue natural gas
sold; and the level of natural gas and NGL prices. We generate our revenues and
our operating margins principally under percent-of-proceeds contractual
arrangements. Under these arrangements, we generally gather natural gas from
producers at the wellhead or central delivery points, move the wellhead natural
gas through our gathering system, treat and process the natural gas and then
sell the resulting residue natural gas and NGLs at published index market
prices. We remit to the producers either an agreed upon percentage of recovered
volumes or the actual proceeds that we receive from our sales of the residue
natural gas and NGLs or an agreed upon percentage of the proceeds based on index
related prices for the natural gas and NGLs. Under these types of arrangements,
our revenues correlate directly with the price of natural gas and NGLs. During
2008, our percent-of-proceeds activities accounted for approximately 77% of our
natural gas throughput volumes. The balance of our throughput volumes are
processed under wellhead purchase contracts, keep-whole contracts, fee based
contracts and hybrid contractual arrangements.





We sell
the majority of our processed natural gas, NGLs and high pressure condensate to
Targa at market-based rates pursuant to natural gas, NGL and condensate purchase
agreements. Low-pressure condensate is sold to third parties. See “Item 13.
Certain Relationships and Related Transactions and Director
Independence.”





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 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 the following: (1) throughput
volumes, (2) facility efficiencies and fuel consumption, (3) operating
margin, (4) operating expenses, (5) Adjusted EBITDA and
(6) distributable cash flow.





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 TABLE OF CONTENTS


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, through additional volumes at existing
central delivery points, 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 the non-generally accepted accounting principle
(“non-GAAP”) financial measure of 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 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. Our non-GAAP
financial measure of 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.








2008
                    
                    
                    2007
                    
                    
                    2006(In
      millions)Reconciliation
      of net income to operating margin:Net
      income
                    
                    $
                    91.5
                    
                    
                    $
                    40.3
                    
                    
                    $
                    11.6Add:Depreciation
      and amortization expense
                    
                    
                    74.3
                    
                    
                    
                    71.8
                    
                    
                    
                    69.9Deferred
      income tax expense
                    
                    
                    1.4
                    
                    
                    
                    1.5
                    
                    
                    
                    2.9Allocated
      interest expense, net
                    
                    
                    -
                    
                    
                    
                    19.4
                    
                    
                    
                    88.0Interest
      expense, net
                    
                    
                    38.3
                    
                    
                    
                    22.0
                    
                    
                    
                    -Gain
      on extinguishment of debt
                    
                    
                    (13.1
                    )
                    
                    
                    -
                    
                    
                    
                    -(Gain)
      loss related to derivatives
                    
                    
                    1.0
                    
                    
                    
                    30.2
                    
                    
                    
                    (16.8
                    )General
      and administrative and other expense
                    
                    
                    22.4
                    
                    
                    
                    18.6
                    
                    
                    
                    16.1Operating
      margin (1)
                    
                    $
                    215.8
                    
                    
                    $
                    203.8
                    
                    
                    $
                    171.7





(1)Includes non-cash charges
related to commodity hedges of $1.0 million, $30.2 million and $(16.8) million
for 2008, 2007 and 2006.


53
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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;





•
            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.





See “Item
6. Selected Consolidated Financial and Operating Data—Non-GAAP Financial
Measures.”





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. Adjusted
EBITDA is another non-GAAP financial measure that is used by us. 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. Our non-GAAP financial measure of 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.





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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.





Year Ended December 31,2008
                  
                  
                  2007
                  
                  
                  2006(In
      millions)Reconciliation
      of net cash provided by operating activities to Adjusted
      EBITDA:Net
      cash provided by operating activities
                  
                  $
                  95.2
                  
                  
                  $
                  270.5
                  
                  
                  $
                  124.4Allocated
      interest expense from parent (1)
                  
                  
                  -
                  
                  
                  
                  18.5
                  
                  
                  
                  81.8Interest
      expense, net (2)
                  
                  
                  36.2
                  
                  
                  
                  21.1
                  
                  
                  
                  -Gain
      on debt extinguishment
                  
                  
                  13.1
                  
                  
                  
                  -
                  
                  
                  
                  -Early
      termination of commodity derivatives
                  
                  
                  87.4
                  
                  
                  
                  -
                  
                  
                  
                  -Other
                  
                  
                  (0.5
                  )
                  
                  
                  (0.1
                  )
                  
                  
                  (0.4
                  )Changes
      in operating working capital which used (provided) cash:Accounts
      receivable and other assets
                  
                  
                  (64.3
                  )
                  
                  
                  (88.8
                  )
                  
                  
                  (80.9
                  )Accounts
      payable and other liabilities
                  
                  
                  61.8
                  
                  
                  
                  (35.4
                  )
                  
                  
                  29.2Adjusted
      EBITDA
                  
                  $
                  228.9
                  
                  
                  $
                  185.8
                  
                  
                  $
                  154.1Reconciliation
      of net income to Adjusted EBITDA:Net
      income
                  
                  $
                  91.5
                  
                  
                  $
                  40.3
                  
                  
                  $
                  11.6Add:Allocated
      interest expense, net
                  
                  
                  -
                  
                  
                  
                  19.4
                  
                  
                  
                  88.0Interest
      expense, net
                  
                  
                  38.3
                  
                  
                  
                  22.0
                  
                  
                  
                  -Deferred
      income tax expense
                  
                  
                  1.4
                  
                  
                  
                  1.5
                  
                  
                  
                  2.9Depreciation
      and amortization expense
                  
                  
                  74.3
                  
                  
                  
                  71.8
                  
                  
                  
                  69.9Non-cash
      (income) loss related to derivatives
                  
                  
                  23.4
                  
                  
                  
                  30.8
                  
                  
                  
                  (18.3
                  )Adjusted
      EBITDA
                  
                  $
                  228.9
                  
                  
                  $
                  185.8
                  
                  
                  $
                  154.1


______________


(1)           Net
of amortization of debt issuance costs of $6.2 million for
2006.


(2)           Net
of amortization of debt issuance costs of $2.1 million and $1.8 million for
2008 and 2007.





Distributable Cash Flow.
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 non-GAAP 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. Our
non-GAAP measure of 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.


55
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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.





Reconciliation
of “Distributable Cash Flow” to Net Income





Year Ended December 31,2008
                    
                    
                    2007
                    
                    
                    2006Reconciliation
      of net income
                    
                    (In
      millions)to
      "distributable cash flow":Net
      income
                    
                    $
                    91.5
                    
                    
                    $
                    40.3
                    
                    
                    $
                    11.6Depreciation
      and amortization expense
                    
                    
                    74.3
                    
                    
                    
                    71.8
                    
                    
                    
                    69.9Deferred
      income tax expense
                    
                    
                    1.4
                    
                    
                    
                    1.5
                    
                    
                    
                    2.9Amortization
      in interest expense
                    
                    
                    2.1
                    
                    
                    
                    1.8
                    
                    
                    
                    6.2Gain
      on debt extinguishment
                    
                    
                    (13.1
                    )
                    
                    
                    -
                    
                    
                    
                    -Non-cash
      (gain) loss related to derivatives
                    
                    
                    23.4
                    
                    
                    
                    30.2
                    
                    
                    
                    (16.8
                    )Maintenance
      capital expenditures
                    
                    
                    (26.7
                    )
                    
                    
                    (21.5
                    )
                    
                    
                    (16.3
                    )Distributable
      cash flow (1)
                    
                    $
                    152.9
                    
                    
                    $
                    124.1
                    
                    
                    $
                    57.5


____________


(1)      Distributable
cash flow for 2007 and 2006 reflect allocated interest from parent of
$19.4 million and $88.0 million.





Below is
a reconciliation of net income as reported and distributable cash flow to which
unit holders are entitled which excludes the results of operations of the North
Texas System and the SAOU and LOU Systems prior to their ownership by the
Partnership.





For
      the Year Ended December 31, 2007Pre-AcquistionTRP LP
                    
                    
                    North
      Texas Jan 1, 2007 to Feb 13, 2007
                    
                    
                    SAOU/LOU
      Jan 1, 2007 to Oct 23, 2007
                    
                    
                    Post
      Acquisition TRP(in
      millions)Reconciliation
      of "Distributable cash flow" to net income:Net
      income (loss)
                    
                    $
                    40.3
                    
                    
                    $
                    (6.9
                    )
                    
                    $
                    19.1
                    
                    
                    $
                    28.1Depreciation
      and amortization expense
                    
                    
                    71.8
                    
                    
                    
                    6.9
                    
                    
                    
                    11.7
                    
                    
                    
                    53.2Deferred
      income tax expense
                    
                    
                    1.5
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    1.5Amortization
      of debt issue costs
                    
                    
                    1.8
                    
                    
                    
                    -
                    
                    
                    
                    0.9
                    
                    
                    
                    0.9Loss(gain)
      on mark-to-market derivative contracts
                    
                    
                    30.2
                    
                    
                    
                    -
                    
                    
                    
                    30.2
                    
                    
                    
                    -Maintenance
      capital expenditures
                    
                    
                    (21.5
                    )
                    
                    
                    (1.5
                    )
                    
                    
                    (5.9
                    )
                    
                    
                    (14.1
                    )Distributable
      cash flow (a)
                    
                    $
                    124.1
                    
                    
                    $
                    (1.5
                    )
                    
                    $
                    56.0
                    
                    
                    $
                    69.6





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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.





Revenue Recognition. Our
primary types of sales and service activities reported as operating revenues
include:





•
            sales
      of natural gas, NGLs and
condensate; and





•
            natural
      gas processing, from which we generate revenues through the compression,
      gathering, treating and processing of natural
  gas.





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 purchases 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 the 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 NGL and incur the risks
and rewards of ownership.





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 at 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 general and administrative costs (2) developing fair value
assumptions, including estimates of future cash flows and discount rates,
(3) analyzing tangible and intangible 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.





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
      ofYearsGas
      gathering systems and processing systems
                        
                        15
      to 25Other
      property and equipment
                        
                        3
      to
7





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 TABLE OF CONTENTS





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. Upon
disposition or retirement of property, plant and equipment, any gain or loss is
charged to operations.





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 the
extent and frequency of maintenance programs. From time to time, we utilize
consultants and other experts to assist us in assessing the remaining lives of
the crude oil or natural gas production in the basins we serve.





We may
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 amount of the assets. We
continually monitor our businesses and the market and business environments to
identify indicators that may suggest an asset may not be
recoverable.





We
evaluate an asset for recoverability by comparing the carrying value of the
asset with the asset’s expected future undiscounted cash flows. These cash flow
estimates require us to make projections and assumptions for many years into the
future for pricing, demand, competition, operating cost and other factors. We
recognize an impairment loss when the carrying amount of the asset exceeds its
fair value as determined by quoted market prices in active markets or present
value techniques if quotes are unavailable. The determination of the fair value
using present value techniques requires us to make projections and assumptions
regarding the probability of a range of outcomes and the rates of interest used
in the present value calculations. Any changes we make to these projections and
assumptions could result in significant revisions to our evaluation of
recoverability of our property, plant and equipment and the recognition of an
impairment loss in our Consolidated Statements of Operations.





Price Risk Management
(Hedging). All derivative instruments not qualifying for the normal
purchases and normal sales exception are recorded on the balance sheet 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 hedge, the
effective portion of the unrealized gain or loss on the derivative is deferred
in accumulated other comprehensive income (“OCI”), a component of partners’
capital 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.





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 becomes
ineffective. 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 probable that a hedged forecasted
transaction will not occur, deferred gains or losses on the hedging instrument
are reclassified to earnings immediately.





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 effectiveness is measured on a
quarterly basis. Any ineffective portion of the unrealized gain or loss is
reclassified to earnings in the current period.





58
 TABLE OF CONTENTS


Estimated Useful Lives. The
estimated useful lives of our long-lived assets are used to compute depreciation
expense, future asset retirement obligations and in impairment testing.
Estimated useful lives are based, among other things, on the assumption that we
provide an appropriate level of maintenance capital expenditures while the
assets are still in operation. Without these continued capital expenditures, the
useful lives of these assets could decrease significantly. Estimated lives could
be impacted by such factors as future energy prices, environmental regulations,
various legal factors and competition. 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.





Accounting
Pronouncements Recently Adopted





In
September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS
157, “Fair Value Measurements.” SFAS 157 establishes a framework for
measuring fair value and expands disclosures about fair value measurements. The
FASB partially deferred the effective date of SFAS 157 for nonfinancial
assets and liabilities that are recognized or disclosed at fair value in the
financial statements on a nonrecurring basis. We adopted SFAS 157 with
respect to financial assets and liabilities that are recognized on a recurring
basis on January 1, 2008. Although the adoption of SFAS 157 did not
materially impact our financial condition, results of operations or cash flow,
we are now required to provide additional disclosures as part of our financial
statements.





SFAS 157
establishes a three-tier fair value hierarchy, which prioritizes the 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. For further discussion and disclosure of SFAS 157 requirements,
see Note 13 to our Consolidated Financial Statements beginning on page F-1 of
this Annual Report.





In
February 2007, the FASB issued SFAS 159, “The Fair Value Option for
Financial Assets and Financial Liabilities, including an amendment of FASB
Statement No. 115.” SFAS 159 expands opportunities to use fair value
measurements in financial reporting and permits entities to choose to measure
many financial instruments and certain other items at fair value. Our adoption
of SFAS 159 on January 1, 2008 did not have a material impact on our
consolidated financial statements.





In March
2008, the FASB issued SFAS 161, “Disclosures
about Derivative Instruments and Hedging Activities — an amendment of FASB
Statement No. 133.”SFAS 161 changes the disclosure requirements for
derivative instruments and hedging activities. Entities are required to provide
enhanced disclosures about (a) how and why an entity uses derivative
instruments, (b) how derivative instruments and related hedged items are
accounted for under SFAS 133, “Derivative
Instruments and Hedging Activities” and its related interpretations and
(c) how derivative instruments and related hedged items affect an entity’s
financial position, financial performance and cash flows. SFAS 161 is effective
for financial statements issued for fiscal years and interim periods beginning
after November 15, 2008. Early adoption is encouraged. Our adoption of SFAS 161
as of December 31, 2008 did not impact our consolidated financial position,
results of operations or cash flows. The additional disclosures required by SFAS
161 are included in Note 9 to Consolidated
Financial Statements, which begins on page F-1.





Accounting
Pronouncements Recently Issued





In March
2008, the FASB’s Emerging Issues Task Force (“EITF”) reached a consensus on
EITF 07-4, “Application of the Two-Class Method under FASB Statement
No. 128, Earnings per Share, to Master Limited Partnerships.”
EITF 07-4 improves the comparability of earnings per unit calculations for
master limited partnerships (“MLPs”) with incentive distribution rights (“IDRs”)
in accordance with Statement 128 and its related interpretations. Under
EITF 07-4, when an MLP’s current-period earnings are in excess of cash
distributions and the IDRs are a separate limited partner interest,
undistributed earnings should be allocated to the general partner (“GP”),
limited partners (“LPs”) and IDR holder utilizing the contractual terms of the
partnership agreement. The distribution formula for available cash specified in
the partnership agreement contractually mandates the way in which earnings are
distributed.





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Additionally,
EITF 07-4 requires an MLP to reflect its contractual obligation to make
distributions as of the end of the current reporting period. Therefore, an MLP
would reduce (increase) income (loss) from continuing operations (or net income
or loss) for the current reporting period by the amount of available cash that
has been or will be distributed to the GP, LPs and IDR holder for that current
reporting period. If distributions to the IDR holder are contractually limited
to available cash as defined in the partnership agreement, then the specified
threshold for the current reporting period would be the holder’s share of
available cash that has been or will be distributed to the IDR holder for that
current reporting period.





EITF 07-4
is effective for financial statements issued for fiscal years beginning after
December 15, 2008 and interim periods within those fiscal years. Earlier
application is not permitted. Our adoption of EITF 07-4 will not impact our
consolidated financial position, results of operations or cash flows. We are
currently evaluating the effect this pronouncement will have on our present
computation of earnings per unit.





Results
of Operations





Our
results of operations for the years ended December 31, 2008, 2007 and 2006 are
presented and evaluated on a combined basis, combining our results with the
results of operations reflected in the audited historical financial statements
of the SAOU and LOU Systems prior to October 24, 2007, with the operations of
the North Texas System prior to February 14, 2007.





The
following table summarizes our combined results of operations for the periods
and as of the dates indicated.





60
 TABLE OF CONTENTS





Year Ended December 31,2008
                
                
                2007
                
                
                2006(In
      millions, except operating and price data)Revenues
                
                $
                2,074.1
                
                
                $
                1,661.5
                
                
                $
                1,738.5Product
      purchases
                
                
                1,803.0
                
                
                
                1,406.8
                
                
                
                1,517.7Operating
      expenses
                
                
                55.3
                
                
                
                50.9
                
                
                
                49.1Depreciation
      and amortization expense
                
                
                74.3
                
                
                
                71.8
                
                
                
                69.9General
      and administrative expense
                
                
                22.4
                
                
                
                18.9
                
                
                
                16.1Other
                
                
                0.1
                
                
                
                -
                
                
                
                -Gain
      on sale of assets
                
                
                (0.1
                )
                
                
                (0.3
                )
                
                
                -Income
      from operations
                
                
                119.1
                
                
                
                113.4
                
                
                
                85.7Interest
      expense, net
                
                
                (38.3
                )
                
                
                (22.0
                )
                
                
                -Interest
      expense allocated from Parent
                
                
                -
                
                
                
                (19.4
                )
                
                
                (88.0
                )Gain
      on extinguishment of debt
                
                
                13.1
                
                
                
                -
                
                
                
                -(Gain)
      loss on mark-to-market derivative instruments
                
                
                (1.0
                )
                
                
                (30.2
                )
                
                
                16.8Deferred
      income tax expense (1)
                
                
                (1.4
                )
                
                
                (1.5
                )
                
                
                (2.9
                )Net
      income
                
                $
                91.5
                
                
                $
                40.3
                
                
                $
                11.6Less:Net
      income attributable to predecessor operations
                
                
                -
                
                
                
                12.2Net
      income allocable to partners
                
                
                91.5
                
                
                
                28.1General
      partner interest in net income
                
                
                7.0
                
                
                
                0.6Net
      income available to common and subordinated unitholders
                
                $
                84.5
                
                
                $
                27.5Net
      income per limited partner unit -basic
                
                $
                1.83
                
                
                $
                0.81Net
      income per limited partner unit -diluted
                
                $
                1.83
                
                
                $
                0.81Cash
      distributions declared per unit
                
                $
                1.97
                
                
                $
                1.24Financial
      and Operating data:Financial
      data:Operating
      margin (2)
                
                $
                215.8
                
                
                $
                203.8
                
                
                $
                171.7Adjusted
      EBITDA (3)
                
                
                228.9
                
                
                
                185.8
                
                
                
                154.1Distributable
      cash flow (4)
                
                
                152.8
                
                
                
                124.1
                
                
                
                57.5Operating
      data:Gathering
      throughput, MMcf/d (5)
                
                
                445.8
                
                
                
                452.0
                
                
                
                433.8Plant
      natural gas inlet, MMcf/d (6)(7)
                
                
                421.2
                
                
                
                429.2
                
                
                
                419.6Gross
      NGL production, MBbl/d
                
                
                42.0
                
                
                
                42.6
                
                
                
                42.4Natural
      gas sales, BBtu/d (7)
                
                
                415.6
                
                
                
                410.2
                
                
                
                489.4NGL
      sales, MBbl/d
                
                
                37.3
                
                
                
                36.4
                
                
                
                36.0Condensate
      sales, MBbl/d
                
                
                3.6
                
                
                
                3.6
                
                
                
                3.3Average
      realized prices:Natural
      Gas, $/MMBtu
                
                
                8.45
                
                
                
                6.60
                
                
                
                6.62NGL,
      $/gal
                
                
                1.17
                
                
                
                1.03
                
                
                
                0.85Condensate,
      $/ Bbl
                
                
                82.52
                
                
                
                65.63
                
                
                
                59.87


____________


(1)
            In
      May 2006, Texas adopted a margin tax, consisting of a 1% tax on the amount
      by which total revenue exceeds cost of goods sold, as apportioned to
      Texas. The amount presented represents our estimated liability for this
      tax.(2)
            Operating
      margin is total operating revenues less product purchases and operating
      expense. See “—How We Evaluate Our Operations—Operating Margin” and
      “Selected Consolidated Financial and Operating Data—Non-GAAP Financial
      Measures.”(3)
            Adjusted
      EBITDA is net income before interest, income taxes, depreciation and
      amortization and non-cash income or loss related to derivative
      instruments. See “—How We Evaluate Our Operations—Adjusted EBITDA” and
      “Selected Consolidated Financial and Operating Data—Non-GAAP Financial
      Measures.”


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(4)
            Distributable
      Cash Flow is net income plus depreciation and amortization and deferred
      taxes, adjusted for losses/(gains) on mark-to-market derivative contracts,
      less maintenance capital expenditures. See “ — How We Evaluate Our
      Operations — Distributable Cash Flow” and “Selected Consolidated
      Financial and Operating Data — Non-GAAP Financial
      Measures.”(5)
            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.(6)
            Plant
      natural gas inlet represented the volume of natural gas passing through
      the meter located at the inlet of a natural gas processing
      plant.(7)
            Plant
      inlet volumes include producer take-in-kind, while natural gas sales
      exclude producer take-in-kind volumes.(8)
            Gross
      NGL production was down during 2008 due to pipeline curtailments and,
      later in the year, due to unfavorable
              processing
      economics.





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





Revenues. Revenues increased
by $412.6 million or 25%, to $2,074.1 million for 2008 compared to
$1,661.5 million for 2007. This increase was primarily due to the following
factors:





·
              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.
 
 ·
              a
      decrease in fee and other revenues of $3.1
  million.
 
 Average
realized sales prices for our sales of:
 
 ·
              natural
      gas increased by $1.85 per MMBtu, or 28%, to $8.45 per MMBtu during 2008
      compared to $6.60 per MMBtu for
2007.
 
 ·
              NGLs
      increased by $0.14 per gallon, or 14%, to $1.17 per gallon for 2008
      compared to $1.03 per gallon for
2007.
 
 ·
              condensate
      increased by $16.89 per Bbl, or 26%, to $82.52 per Bbl for 2008
      compared to $65.62 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. Net NGL sales increased by 0.9 MBbl/d or 2%, to 37.3MBbl/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.





Depreciation and Amortization
Expense. Depreciation and amortization expense for 2008 was
$74.3 million compared to $71.8 million for 2007, an increase of
$2.5 million or 3%. The increase is due to the higher carrying value of
property, plant and equipment as a result of plant and gathering system
expansions.





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General and Administrative
Expense. General and administrative expense of $22.4 million for
2008 is an increase of $3.5 million or 19%, compared to $18.9 million for
2007. The increase included increases in professional service fees, insurance
expenses, allocated corporate level expenses and other general and
administrative expenses, partially offset by a decrease in compensation related
expenses.  For additional information regarding our allocation of
general and administrative costs, see “Item 13. Certain Relationships and
Related Transactions, and Director Independence-Omnibus Agreement” in this
Annual Report.





Interest Expense. Interest
expense for 2008 was $38.3 million compared to $41.4 million in 2007.
Excluding interest expense allocated from our parent of $19.4 million in 2007
for the periods prior to our acquisition of our businesses from Targa, our
interest expense increased by $16.3 million, because the debt portion of our
acquisition financing was outstanding for the full year in 2008 and due to
higher interest expense on our senior secured notes as compared to our credit
facility.





Year
Ended December 31, 2007 Compared to Year Ended December 31,
2006





Revenues. Revenues decreased
by $77.0 million or 4.4%, to $1,661.5 million for 2007 compared to
$1,738.5 million for 2006. This decrease was primarily due to the
following:





•
            a
      net increase attributable to prices of $102.5 million, consisting of
      a decrease in natural gas revenues of $3.9 million and increases in
      NGL and condensate revenues of $99.0 million and
      $7.4 million;





•
            a
      net decrease attributable to volumes of $181.2 million, consisting of
      a decrease in natural gas revenues of $191.6 million and increases of
      NGL and condensate revenues of $5.7 million and
      $4.8 million; and





•
            an
      increase in fee and other revenues of
  $1.6 million.





Average
      realized prices for our sales of:





•
            natural
      gas decreased by $0.03 per MMBtu or less than 1%, to $6.60 per MMBtu
      during 2007 compared to $6.63 per MMBtu for
  2006.





•
            NGLs
      increased by $0.18 per gallon or 21%, to $1.03 per gallon for 2007
      compared to $0.85 per gallon for
2006.





•
            condensate
      increased by $5.75 per Bbl or 10%, to $65.62 per Bbl for 2007
      compared to $59.87 per Bbl for
2006.





Natural
gas sales volume decreased by 79.2 BBtu/d or 16%, to 410.2 BBtu/d during 2007
compared to 489.4 BBtu/d for 2006. The decrease in sales of natural gas volumes
was attributable to a net decrease in natural gas purchased from affiliates and
increased take-in-kind volumes by producers for whom we process natural gas,
offset by net increases in other non-wellhead supply sources and wellhead
supplies attributable to additional well connections which were partially offset
by the natural decline of field production. Net NGL sales increased by
0.4 MBbl/d or 1%, to 36.4 MBbl/d for 2007 compared to 36.0 MBbl/d
for 2006. The volume increase was primarily attributable to additional well
connections partially offset by the natural decline in field production.
Condensate production increased by 0.3 MBbl/d or 9%, to 3.6 MBbl/d for
2007 compared to 3.3 MBbl/d for 2006.





Product Purchases. Product
purchases during 2007 were $1,406.8 million, a decrease of
$110.9 million or 7%, compared to $1,517.7 million during
2006.





Operating Expenses. Operating
expenses during 2007 were $50.9 million, an increase of $1.8 million
or 4%, compared to $49.1 million during 2006. The increase was partially
attributable to increased operating costs due to our processing plant and
gathering system expansions, as well as increased prices for labor, supplies and
equipment.





Depreciation and Amortization
Expense. Depreciation and amortization expense for 2007 was
$71.8 million compared to $69.9 million for 2006, an increase of
$1.9 million or 3%. The increase is due to the higher carrying value of
property, plant and equipment as a result of plant and gathering system
expansions.





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 TABLE OF CONTENTS


General and Administrative
Expense. General and administrative expense of $18.9 million for
2007 is an increase of $2.8 million or 17%, compared to $16.1 million
for 2006. The general and administrative expense increase was primarily
attributable to higher direct general and administrative costs of being a public
reporting entity in 2007 of approximately $3.1 million.





Interest Expense. Interest
expense for 2007 was $41.4 million. Allocated interest expense from Targa
in 2006 was $88.0 million. Interest expense in 2007 consisted of (i) a
$9.6 million allocation from Targa for the periods from January 1,
2007 through October 24, 2007 related to the SAOU and LOU Systems,
(ii) a $9.8 million allocation from January 1 through
February 13, 2007 related to the North Texas System and
(iii) $22.0 million of interest for borrowings under our credit
facility. See “—Liquidity and Capital Resources” for additional information
regarding our outstanding debt obligations.





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
depends 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 commodity prices, particularly for natural gas and NGLs, operating
costs and maintenance capital expenditures. See “Item 1A.—Risk
Factors.”





Our main
sources of liquidity and capital resources are internally generated cash flow
from operations, a credit facility with both uncommitted and committed
availability and access to both the debt and equity capital markets. The credit
markets are undergoing significant volatility. Many financial institutions have
liquidity concerns, prompting government intervention to mitigate pressure on
the credit markets. Our exposure to the current credit crisis includes our
credit facility, cash investments and counterparty performance risks. Continued
volatility in the capital 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. In order to increase our cash
position in the face of the credit and capital market disruptions, on
October 16, 2008, we requested a $100 million funding under our credit
facility. Lehman Bank, a lender under our credit facility, defaulted on its
portion of this borrowing request resulting in actual funding of
$97.8 million. As a result of the default by Lehman Bank, we believe the
availability under our credit facility has been effectively reduced by
approximately $10.0 million.




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. 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 materially adverse
effect on our results of operations. We sell a significant portion of our
natural gas, NGLs and condensate to Targa and a variety of other purchasers.
Non-performance by a trade creditor could result in losses.




Crude oil
and natural gas prices are also volatile and have declined significantly during
the later half of 2008. In a continuing effort to reduce the volatility of our
cash flows, we have periodically entered into commodity contracts for a portion
of our estimated equity volumes through 2012. See “Item 7A. Quantitative and
Qualitative Disclosures about Market Risk—Commodity Price Risk” and Note 9 to
our Consolidated Financial Statements beginning on page F-1 of this Annual
Report. The current market conditions may also impact our ability to enter into
future commodity derivative contracts. In the event of a 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, 2008, we had liquidity of $424.3 million, including $81.8 million
of cash and $342.5 million of additional borrowing capacity available under our
credit facility. We will continue to monitor our liquidity and conditions in the
capital markets. Additionally, we will continue to monitor events and
circumstances surrounding each of the other twenty three lenders under 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. See “Item 1A. Risk
Factors” in this Annual Report.




Historically,
our cash generated from operations has been sufficient to finance our operating
expenditures and fund most of our maintenance and expansion capital
expenditures, with remaining amounts being distributed to Targa during its
period of ownership and to our unitholders since our IPO.


64
 TABLE OF CONTENTS





We
believe that cash generated from operations along with availability under our
credit facility will be sufficient to meet our working capital requirements,
capital expenditure requirements and our minimum quarterly cash distributions
for at least the next year.





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 subsequent to the fourth quarter of 2008 and
distributions declared and paid in 2008 and 2007.





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
our IPO and 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 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, 2008, we had a positive working capital balance of
$149.0 million.





Cash Flow. Net cash provided
by or used in operating activities, investing activities and financing
activities for 2008, 2007 and 2006 were as follows:





Year
      Ended December 31,2008
                
                
                2007
                
                
                2006(In
      millions)Net
      cash provided by (used in):Operating
      activities
                
                $
                95.2
                
                
                $
                270.5
                
                
                $
                124.4Investing
      activities
                
                
                (51.0
                )
                
                
                (40.7
                )
                
                
                (32.9
                )Financing
      activities
                
                
                (13.5
                )
                
                
                (178.8
                )
                
                
                (91.5
                )





Operating Activities. Net
cash provided by operating activities for 2008 decreased by $175.3 million or
65% compared to 2007. This decrease is primarily attributable to a decrease in
working capital balances and an $87.4 million payment to terminate certain
out-of-the-money commodity derivatives, partially offset by a $51.2 million
increase in net income.





Net cash
provided by operating activities increased by $146.1 million or 117%, for
2007 compared to 2006. This increase is attributable to an increase in our net
income, increased non-cash charges and increases in working capital
balances.


65
 TABLE OF CONTENTS





Investing Activities. Net
cash used in investing activities for 2008 increased $10.3 million or 25%
compared to 2007. The increase is primarily from increased expenditures related
to gathering system expansion projects begun in the third quarter of
2008.





Net cash
used in investing activities for 2007 increased $7.8 million or 24%, compared to
2006, primarily due to the completion of gathering system expansion projects and
higher major maintenance expenditures. The increase of $5.6 million in expansion
projects and major maintenance expenditures resulted from the increased size of
our gathering systems and the effect of higher utilization of our field
compression facilities.





Financing Activities. Net
cash used in financing activities for 2008 decreased by $165.3 million, or
92% compared to 2007. Cash flows from financing activities during 2007 included
activity related to our IPO and our acquisition from Targa of the SAOU and LOU
systems. During 2008, net borrowings of $111.5 million were offset by a $26.8
million payment to repurchase approximately $40 million of our senior notes and
a $59.7 million increase in distributions to our unitholders.





The net
cash used in financing activities for 2007 increased by $87.3 million compared
to 2006. This increase primarily reflects the proceeds from our equity
offerings, borrowings under our credit facility and deemed parent contributions
prior to the contribution or transfer of assets to us, partially offset by
payments of debt, offering costs, debt issuance costs related to our credit
facility, distributions to our equity holders and payments to Targa for assets
transferred under common control.





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 incur
significant expenditures throughout 2009 related to the expansion of our natural
gas gathering and processing infrastructure.





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 31,2008
                
                
                2007
                
                
                2006(In
      millions)Capital
      expenditures:Expansion
                
                $
                28.0
                
                
                $
                22.4
                
                
                $
                16.0Maintenance
                
                
                26.6
                
                
                
                21.5
                
                
                
                16.3$
                54.6
                
                
                $
                43.9
                
                
                $
                32.3





We
estimate that our capital expenditures will be approximately $60 million in
2009, of which approximately $20 million will be for maintenance. 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.





Description of Senior
Notes.  On June 12, 2008, we entered into a purchase
agreement to issue and sell $250,000,000 in aggregate principal amount of our
81/4%
senior unsecured notes due 2016 (the “Notes”).  On June 18, 2008,
in connection with the issuance of the Notes, we entered into an Indenture (the
“Indenture”) governing the terms of the Notes.





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





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 TABLE OF CONTENTS


The
Indenture restricts our ability to make distributions to unitholders if we are
in default or an event of default (as defined in the 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 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
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 Senior Secured Credit
Agreement.See Note 10 to our Consolidated Financial Statements beginning
on page F-1 of this Annual Report for a complete description of our Senior
Secured Credit Facility..





Contractual Obligations.
Following is a summary of our contractual cash obligations over the next several
fiscal years, as of December 31, 2008:





Payments Due By PeriodContractual Obligations
                
                Total
                
                
                Less Than 1 Year
                
                
                1-3 Years
                
                
                4-5 Years
                
                
                More Than 5 Years(In
      millions)Debt
      obligations (1)
                
                $
                696.9
                
                
                $
                -
                
                
                $
                -
                
                
                $
                487.8
                
                
                $
                209.1Interest
      on debt obligations (2)
                
                
                159.8
                
                
                
                27.0
                
                
                
                54.0
                
                
                
                35.7
                
                
                
                43.1Capacity
      payments (3)
                
                
                8.2
                
                
                
                5.4
                
                
                
                2.8
                
                
                
                -
                
                
                
                -Right-of-way
                
                
                4.9
                
                
                
                0.3
                
                
                
                0.7
                
                
                
                0.6
                
                
                
                3.3Asset
      retirement obligation
                
                
                3.5
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                3.5$
                873.3
                
                
                $
                32.7
                
                
                $
                57.5
                
                
                $
                524.1
                
                
                $
                259.0


____________





(1)
            Represents
      $209.1 million outstanding on the 81⁄4% senior notes due July 1, 2016 and
      $487.8 million outstanding under our $850 million senior secured credit
      facility. As of December 31, 2008, we had availability under our credit
      facility of $342.5 million, after giving effect to outstanding borrowings
      of $487.8 million, $9.7 million of issued letters of credit and the Lehman
      Bank default of approximately $10.0 million.(2)
            Represents
      interest expense on our debt, based on interest rates as of
      December 31, 2008.(3)
            Consists
      of payments for firm natural gas pipeline
  capacity.








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 TABLE OF CONTENTS


Item
7A. Quantitative and QualitativeDisclosures 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 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, 2008, we have hedged the
commodity price associated with a significant portion of our expected natural
gas, NGL and condensate equity volumes for the years 2009 through 2012 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, 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 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 (“ISDA”) 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 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
2008, 2007 and 2006, 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 2008, 2007 and 2006, our operating revenues
were adjusted by net hedge losses of $33.7 million, $1.0 million and
$0.9 million.





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As of
December 31, 2008, our commodity hedges were as follows:





Natural
      GasAvg.
      Price
                      
                      
                      MMBtu per dayInstrument Type
                      Index
                      
                      $/MMBtu
                      
                      
                      2009
                      
                      
                      2010
                      
                      
                      2011
                      
                      
                      2012
                      
                      Fair Value(In
      thousands)Natural
      Gas SalesSwap
                      IF-HSC
                      
                      
                      7.39
                      
                      
                      
                      1,966
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      $
                      1,1591,966
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -Swap
                      IF-NGPL
      MC
                      
                      
                      9.18
                      
                      
                      
                      6,256
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      9,466Swap
                      IF-NGPL
      MC
                      
                      
                      8.86
                      
                      
                      
                      -
                      
                      
                      
                      5,685
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      5,129Swap
                      IF-NGPL
      MC
                      
                      
                      7.34
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      2,750
                      
                      
                      
                      -
                      
                      
                      
                      843Swap
                      IF-NGPL
      MC
                      
                      
                      7.18
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      2,750
                      
                      
                      
                      7386,256
                      
                      
                      
                      5,685
                      
                      
                      
                      2,750
                      
                      
                      
                      2,750Swap
                      IF-Waha
                      
                      
                      8.73
                      
                      
                      
                      6,936
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      8,627Swap
                      IF-Waha
                      
                      
                      7.52
                      
                      
                      
                      -
                      
                      
                      
                      5,709
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      2,294Swap
                      IF-Waha
                      
                      
                      7.36
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      3,250
                      
                      
                      
                      -
                      
                      
                      
                      886Swap
                      IF-Waha
                      
                      
                      7.18
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      3,250
                      
                      
                      
                      7086,936
                      
                      
                      
                      5,709
                      
                      
                      
                      3,250
                      
                      
                      
                      3,250Total
      Swaps
                      
                      
                      
                      
                      
                      
                      
                      15,158
                      
                      
                      
                      11,394
                      
                      
                      
                      6,000
                      
                      
                      
                      6,000Floor
                      IF-NGPL
      MC
                      
                      
                      6.55
                      
                      
                      
                      850
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      574850
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -Floor
                      IF-Waha
                      
                      
                      6.55
                      
                      
                      
                      565
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      326565
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -Total
      Floors
                      
                      
                      
                      
                      
                      
                      
                      1,415
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -Total
      Sales
                      
                      
                      
                      
                      
                      
                      
                      16,573
                      
                      
                      
                      11,394
                      
                      
                      
                      6,000
                      
                      
                      
                      6,000$
                      30,750NGLAvg.
      Price
                      
                      
                      Barrels per dayInstrument Type
                      Index
                      
                      $/gal
                      
                      
                      2009
                      
                      
                      2010
                      
                      
                      2011
                      
                      
                      2012
                      
                      Fair Value(In
      thousands)NGL
      SalesSwap
                      OPIS-MB
                      
                      
                      1.32
                      
                      
                      
                      6,248
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      $
                      66,137Swap
                      OPIS-MB
                      
                      
                      1.27
                      
                      
                      
                      -
                      
                      
                      
                      4,809
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      39,122Swap
                      OPIS-MB
                      
                      
                      0.92
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      3,400
                      
                      
                      
                      -
                      
                      
                      
                      8,288Swap
                      OPIS-MB
                      
                      
                      0.92
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      2,700
                      
                      
                      
                      6,018Total
      Swaps
                      
                      
                      
                      
                      
                      
                      
                      6,248
                      
                      
                      
                      4,809
                      
                      
                      
                      3,400
                      
                      
                      
                      2,700Floor
                      OPIS-MB
                      
                      
                      1.44
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      199
                      
                      
                      
                      -
                      
                      
                      
                      1,807Floor
                      OPIS-MB
                      
                      
                      1.43
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      231
                      
                      
                      
                      1,932Total
      Floors
                      
                      
                      
                      
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      199
                      
                      
                      
                      231Total
      Sales
                      
                      
                      
                      
                      
                      
                      
                      6,248
                      
                      
                      
                      4,809
                      
                      
                      
                      3,599
                      
                      
                      
                      2,931$
                      123,304


69
 TABLE OF CONTENTS





CondensateAvg.
      Price
                        
                        
                        Barrels per dayInstrument Type
                        Index
                        
                        $/Bbl
                        
                        
                        2009
                        
                        
                        2010
                        
                        
                        2011
                        
                        
                        2012
                        
                        
                        Fair Value(In
      thousands)Condensate
      SalesSwap
                        NY-WTI
                        
                        
                        69.00
                        
                        
                        
                        322
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        $
                        1,655Swap
                        NY-WTI
                        
                        
                        68.10
                        
                        
                        
                        -
                        
                        
                        
                        301
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        431Total
      Swaps
                        
                        
                        
                        
                        
                        
                        
                        322
                        
                        
                        
                        301
                        
                        
                        
                        -
                        
                        
                        
                        -Floor
                        NY-WTI
                        
                        
                        60.00
                        
                        
                        
                        50
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        239Total
      Floors
                        
                        
                        
                        
                        
                        
                        
                        50
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -Total
      Sales
                        
                        
                        
                        
                        
                        
                        
                        372
                        
                        
                        
                        301
                        
                        
                        
                        -
                        
                        
                        
                        -$
                        2,325





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.





Interest Rate Risk. We are
exposed to changes in interest rates, primarily as a result of our variable rate
debt 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, 2008, there were borrowings of approximately
$487.8 million outstanding under our $850 million credit
facility.





As of
December 31, 2008 we had the following open interest rate
swaps:





Notional
                                AmountExpiration Date
                              
                              Fixed Rate
                              
                              Amount
                              
                              Fair Value(In
      thousands)January
      24, 2011
                              
                              
                              4.00
                              %
                              $100
      million
                              
                              $
                              (5,282
                              )January
      24, 2012
                              
                              
                              3.75
                              %
                              200
      million
                              
                              
                              (12,294
                              )$
                              (17,576
                              )





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 $1.9 million.





Credit Risk. We are subject
to risk of losses resulting from nonpayment or nonperformance by our customers.
We operate under the Targa credit policy and closely monitor the
creditworthiness of customers to whom we grant credit and establish credit
limits in accordance with this credit policy. In addition to third party
contracts, we have entered into several agreements with Targa. For example, we
are party to natural gas, NGL and condensate purchase agreements pursuant to
which Targa purchases the majority of our natural gas, NGLs and high-pressure
condensate. In addition, we are also a party to an omnibus agreement with Targa
which addresses, among other things, the provision of general and administrative
and operating services to us. 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.





As of
December 31, 2008, affiliates of Goldman Sachs, Merrill Lynch and Barclays Bank
accounted for 67%, 21% and 11% of our counterparty credit exposure related to
commodity derivative instruments. Goldman Sachs, Merrill Lynch and Barclays Bank
are major financial institutions, each possessing investment grade credit
ratings, based upon minimum credit ratings assigned by Standard & Poor’s
Ratings Services, a division of the McGraw-Hill Companies, Inc.











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Item 8.Financial Statementsand 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
Disagreementswith 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, 2008, have
concluded that as of December 31, 2008, 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, 2008 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.






(b)
Report of Independent Registered Public Accounting Firm






The
effectiveness of the Partnership’s internal control over financial reporting as
of December 31, 2008, has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in its report included
in our Consolidated Financial Statements on page F-3 of this Annual Report which
is incorporated herein by reference.






(c) Changes in Internal Control Over
Financial Reporting






During
the quarter ended December 31, 2008, 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





Not
applicable.








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Part III








Item 10.Directors,
ExecutiveOfficers and Corporate Governance





We are a
limited partnership and, therefore, have no officers or directors.





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 and our general partner has three directors
that are independent as defined under the independence standards established by
The NASDAQ Stock Market LLC. The NASDAQ Stock Market LLC 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 committee.





Our
general partner has a standing 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 of Directors of our general
partner has affirmatively determined that Messrs. Evans, Pearl and Sullivan
are independent as described in the rules of The NASDAQ Stock Market LLC and the
Exchange Act, as amended. In addition, the Board of Directors of our general
partner has 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, with
the board of directors of our general partner 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 of directors of our general
partner. While the board may establish a compensation committee in the future,
it has no current plans to do so.





Three
independent members of the board of directors of our general partner serve on a
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 NASDAQ Stock Market LLC
and the Exchange Act, amended, 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.





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All of
our executive management personnel are employees of Targa and devote their time
as needed to conduct our business and affairs. These officers of Targa Resources
GP LLC manage the day-to-day affairs of our business. We also utilize a
significant number of employees of Targa 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
                                                            61
                                                            Chief
      Executive Officer and DirectorJoe
      Bob Perkins
                                                            48
                                                            PresidentJames
      W. Whalen
                                                            67
                                                            President — Finance
      and Administration and DirectorRoy
      E. Johnson
                                                            64
                                                            Executive
      Vice PresidentMichael
      A. Heim
                                                            60
                                                            Executive
      Vice President and Chief Operating OfficerJeffrey
      J. McParland
                                                            54
                                                            Executive
      Vice President and Chief Financial OfficerPaul
      W.
      Chung
                                                            48
                                                            Executive
      Vice President, General Counsel and SecretaryPeter
      R.
      Kagan
                                                            40
                                                            DirectorChansoo
      Joung
                                                            48
                                                            DirectorRobert
      B. Evans
                                                            60
                                                            DirectorBarry
      R.
      Pearl
                                                            59
                                                            DirectorWilliam
      D. Sullivan
                                                            52
                                                            Director


__________





(1)
            As
      of February 25, 2009





Our
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 of directors of our general
partner. There are no family relationships among any of our 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.





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.





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 TABLE OF CONTENTS


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 Parker Drilling Company and
Equitable Resources, Inc.





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.





Paul W. Chunghas served as
Executive Vice President, General Counsel and Secretary of our general partner
since October 2006 and of Targa since May 2004. Mr. Chung served as
Executive Vice President and General Counsel of Coral from 1999 to April 2004;
Shell Trading North America Company, a subsidiary of Shell, from 2001 to April
2004; and Coral Energy, LLC from 1999 to 2001. In these positions, he was
responsible for all legal and regulatory affairs. He served as Vice President
and Assistant General Counsel of Tejas from 1996 to 1999. Prior to 1996,
Mr. Chung held a number of legal positions with different companies,
including the law firm of Vinson & Elkins L.L.P.





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, MEG
Energy Corp. and Universal Space Network, Inc.





74
 TABLE OF CONTENTS


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 APT
Generation, Broad Oak, Ceres, Inc. and Floridian Natural Gas Storage
Company.





Robert B. Evanshas served as
a director of our general partner since February 2007. 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.





Barry R. Pearlhas served as
a director of our general partner since February 2007. Mr. Pearl is a
principal of Kealine LLC, a private developer and operator of petroleum
infrastructure facilities and is a director of Seaspan Corporation and Kayne
Anderson Energy Development Company. 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.





William D. Sullivanhas
served as a director of our general partner since February 2007.
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 is a director of
St. Mary Land & Exploration Company, Legacy Reserves GP, LLC and
Tetra Technologies, Inc.





Reimbursement
of Expenses of our General Partner





Under the
terms of 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 are capped at $5 million annually
      for three years (ending February 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 expenses, which are not subject to the $5 million
      cap for general and administrative
expenses.





With
respect to the SAOU and LOU Systems, we will reimburse Targa for the following
expenses:





•
            general
      and administrative expenses, which are not capped, allocated to the SAOU
      and LOU Systems according to Targa’s allocation
      practice; and





•
            operating
      and certain direct expenses, which are not
  capped.





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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.





General
and administrative costs will continue to be allocated to the SAOU and LOU
Systems according to Targa’s allocation practice.





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. 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 under Item 10 of a current report
on Form 8-K.





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, the Code of Ethics 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 telephone
(713) 584-1000. The information contained on or connected to, our internet
website is not incorporated by reference into this Annual Report on
Form 10-K and should not be considered part of this or any other report
that the we file with or furnish to the SEC.





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 2008, 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





We do not
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 its board of directors (the “Board”), which does not have a
compensation committee. All of our executive officers are employees of Targa
Resources LLC, a wholly-owned subsidiary of Targa 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 executive officers based on
Targa’s methodology used for allocating general and administration expenses
during a period pursuant to the terms of and subject to the limitations
contained in, the Amended and Restated Omnibus Agreement. During 2006, our
executive officers were not specifically compensated for time expended with
respect to our business or assets.





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Targa
Investments has ultimate decision making authority with respect to the
compensation of our 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 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
named executive officers that is based on Targa Investments’ business
priorities.





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





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For 2008,
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 2008 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 reviews our compensation practices and performance against peer
companies on 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 Senior Management
for additional information or to reconsider their recommendation.  The
resulting recommendation is then submitted to the TRII Compensation Committee
for consideration. 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 are designed to 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 employees, including our named executive officers, are subject to the
sole discretion of the TRII Compensation Committee.





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Our 2008
Annual Incentive Plan (the “Bonus Plan”) was adopted on January 17, 2008 to
reward our employees for contributions towards our achievement of financial and
operational business priorities (which includes business priorities of the
Partnership) approved by the TRII Compensation Committee and to aid us in
retaining and motivating employees. Under the Bonus Plan and similar plans
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. The Bonus Plan is administered by the TRII
Compensation Committee, which considers certain recommendations by the CEO.
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 certain of our departments, groups and employees (other
than our executive officers) based on performance and on the recommendation of
their supervisors, managers and line officers.





For 2008,
the TRII Compensation Committee approved funding of the cash bonus pool with the
following six key business priorities: (i) identify opportunities to
strengthen organization and develop plans to address them; (ii) expand on
existing processes to enhance the involvement of the organization in making our
businesses better; (iii) aggressively develop attractive return projects
and opportunities and proactively invest in and expand the Company’s businesses;
(iv) improve insurance recovery situation with resolution or clear path to
resolution; (v) make a significant third-party acquisition(s) at the
Partnership and/or continue to effectively drop down Company assets to the
Partnership; and (vi) execute on all fronts (including the 2008 business
plan and above priorities).  The Bonus Plan established business
priorities that the TRII Compensation Committee considers when making awards
under the Bonus Plan and 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 funding of the cash bonus pool and the payment of individual cash
bonuses to employees, including our named executive officers, are subject to the
sole discretion of the TRII Compensation Committee.





LTIP Awards.  In
January 2008, Targa Investments granted to the named executive officers
cash-settled performance unit awards linked to the performance of the
Partnership’s common units that will vest in June of 2011, 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 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;
(ii) an amount equal to the employee’s contributions to the 401(k) Plan up
to 5% of the employee’s eligible compensation and (iii) a discretionary
amount 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.





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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
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 our parent’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 our own business
strategies and to attract, motivate and retain high quality talent with the
skills and competencies required by Targa Investments and us.





Application
of Compensation Elements





Equity Ownership. The TRII
Compensation Committee did not award additional equity to the named executive
officers in 2008.





Base Salary.  In
2008, 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.  In January 2009, the TRII Compensation Committee
approved a cash bonus pool of 150% of the target level for the employee group,
including our named executive officers, under the Bonus Plan for performance
during 2008. The TRII Compensation Committee paid above target level bonuses
under the Bonus Plan in recognition of significant efforts and organizational
performance in 2008. The executive officers received bonus awards equivalent to
the same percentage of target as the Company bonus pool based on our achievement
of overall goals in 2008 as follows:





Rene
      R. Joyce
                      
                      $
                      247,500Jeffrey
      J. McParland
                      
                      
                      194,250Joe
      Bob Perkins
                      
                      
                      222,750James
      W. Whalen
                      
                      
                      222,750Michael
      A. Heim
                      
                      
                      206,250





Long-term Cash
Incentives.  In January 2008, 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, 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
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 LLC. 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.





Health and Welfare
Benefits.  For 2008, 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 2008, other than parking
subsidies.


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Changes
for 2009





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 January 2009, the TRII Compensation Committee approved the Targa Investments
2009 Annual Incentive Compensation Plan (the “2009 Bonus Plan”), the cash bonus
plan for performance during 2009, and, established the following eight key
business priorities:(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 TRI 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.   As with the Bonus Plan, funding
of the cash bonus pool and the payment of individual cash bonuses to employees,
including our named executive officers, are subject to the sole discretion of
the TRII Compensation Committee.





Long-term Cash
Incentives.  In January 2009, our named executive officers, who
are also executive officers of the General Partner, received an award of
performance units under Targa Investments’ long-term incentive plan 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.





Compensation
Committee Interlocks and Insider Participation





Our
general partner does not maintain a compensation committee. The following
officers of our general partner participated in deliberations of the
Compensation Committee of Targa Investments concerning executive officer
compensation: Messrs. Joyce, Perkins, Heim, Johnson, McParland 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 on Form 10-K. Based on these reviews and discussions, the Board
recommended that the compensation discussion and analysis be included in the
Annual Report on Form 10-K for the year ended December 31, 2008 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


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Executive
Compensation





The
following Summary Compensation Table sets forth the compensation of our named
executive officers for 2008, 2007 and 2006. 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 2008Non-EquityStock
                              
                              
                              Option
                              
                              
                              Incentive
      Plan
                              
                              
                              All
      Other
                              
                              
                              TotalName
                              
                              Year
                              
                              Salary
                              
                              
                              Awards ($)(1)
                              
                              
                              Awards ($)(2)
                              
                              
                              Compensation
                              
                              
                              Compensation(3)
                              
                              
                              CompensationRene
      R. Joyce
                              
                              2008
                              
                              $
                              322,500
                              
                              
                              $
                              148,218
                              
                              
                              $
                              1,524
                              
                              
                              $
                              247,500
                              
                              
                              $
                              19,205
                              
                              
                              $
                              738,947Chief
      Executive Officer
                              
                              2007
                              
                              
                              293,750
                              
                              
                              
                              459,769
                              
                              
                              
                              3,244
                              
                              
                              
                              300,000
                              
                              
                              
                              817,963
                              
                              
                              
                              1,874,7262006
                              
                              
                              266,530
                              
                              
                              
                              312,513
                              
                              
                              
                              3,244
                              
                              
                              
                              264,000
                              
                              
                              
                              25,236
                              
                              
                              
                              871,523Jeffrey
      J. McParland
                              
                              2008
                              
                              
                              253,000
                              
                              
                              
                              114,247
                              
                              
                              
                              1,524
                              
                              
                              
                              194,250
                              
                              
                              
                              19,031
                              
                              
                              
                              582,052Executive
      Vice President and
                              
                              2007
                              
                              
                              230,000
                              
                              
                              
                              316,770
                              
                              
                              
                              3,244
                              
                              
                              
                              235,000
                              
                              
                              
                              674,292
                              
                              
                              
                              1,459,306Chief
      Financial Officer
                              
                              2006
                              
                              
                              210,280
                              
                              
                              
                              236,720
                              
                              
                              
                              3,244
                              
                              
                              
                              206,400
                              
                              
                              
                              23,086
                              
                              
                              
                              679,730Joe
      Bob Perkins
                              
                              2008
                              
                              
                              290,250
                              
                              
                              
                              126,228
                              
                              
                              
                              1,524
                              
                              
                              
                              222,750
                              
                              
                              
                              19,124
                              
                              
                              
                              659,876President
                              
                              2007
                              
                              
                              265,000
                              
                              
                              
                              366,318
                              
                              
                              
                              3,244
                              
                              
                              
                              270,000
                              
                              
                              
                              817,888
                              
                              
                              
                              1,722,4502006
                              
                              
                              244,030
                              
                              
                              
                              260,294
                              
                              
                              
                              3,244
                              
                              
                              
                              240,000
                              
                              
                              
                              23,174
                              
                              
                              
                              770,742James
      W. Whalen
                              
                              2008
                              
                              
                              290,250
                              
                              
                              
                              66,488
                              
                              
                              
                              -
                              
                              
                              
                              222,750
                              
                              
                              
                              18,871
                              
                              
                              
                              598,359President—Finance
      and
                              
                              2007
                              
                              
                              265,000
                              
                              
                              
                              224,796
                              
                              
                              
                              -
                              
                              
                              
                              270,000
                              
                              
                              
                              817,888
                              
                              
                              
                              1,577,684Administration
                              
                              2006
                              
                              
                              244,030
                              
                              
                              
                              227,546
                              
                              
                              
                              -
                              
                              
                              
                              240,000
                              
                              
                              
                              21,926
                              
                              
                              
                              733,502Michael
      A. Heim
                              
                              2008
                              
                              
                              268,750
                              
                              
                              
                              127,172
                              
                              
                              
                              1,524
                              
                              
                              
                              206,250
                              
                              
                              
                              19,071
                              
                              
                              
                              622,767Executive
      Vice President and
                              
                              2007
                              
                              
                              243,750
                              
                              
                              
                              366,318
                              
                              
                              
                              3,244
                              
                              
                              
                              250,000
                              
                              
                              
                              817,838
                              
                              
                              
                              1,681,150Chief
      Operating Officer
                              
                              2006
                              
                              
                              217,791
                              
                              
                              
                              260,294
                              
                              
                              
                              3,244
                              
                              
                              
                              216,000
                              
                              
                              
                              23,111
                              
                              
                              
                              720,440


__________


(1)
            Amounts
      represent expense recognized for financial statement reporting purposes in
      accordance with SFAS 123(R) with respect to restricted stock awards and
      performance unit awards, disregarding any estimate of forfeitures related
      to service-based vesting conditions. No stock awards or performance unit
      awards granted to the named executive officers were forfeited during
      2008.  No stock awards were granted to the named executive
      officers during 2008. Detailed information about the amount recognized for
      specific awards is reported in the table under “Outstanding Equity Awards
      at 2008 Fiscal Year-End” below. The fair value of non-vested stock is
      measured on the grant date using the estimated market price of Targa
      Investments common stock on such date. 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 fair value of the call options were
      estimated with a Black-Scholes option pricing model using a dividend yield
      of zero, risk-free rates of 0.9% and 0.6% for 2008 and 2007 and
      volatilities of 41% and 59% for the same
  periods.


(2)
            Amounts
      represent expense recognized for financial statement reporting purposes in
      accordance with SFAS 123(R) with respect to option awards, disregarding
      any estimate of forfeitures related to service-based vesting conditions.
      No option awards granted to the named executive officers were forfeited
      during 2008. No option awards were granted to the named executive officers
      during 2008.  Detailed information about the amount recognized
      for specific awards is reported in the table under “Outstanding Equity
      Awards at 2008 Fiscal Year-End” below. The fair value of each option
      granted was estimated on the date of grant using a Black-Scholes option
      pricing model, which incorporates various assumptions for 2008, 2007 and
      2006, including (i) expected term of the options of ten years,
      (ii) a risk-free interest rate of 3.6%, 4.6% and 4.5%,
      (iii) expected dividend yield of 0%, and (iv) expected stock
      price volatility on Targa Investments’ common stock of 25.5%, 29.7% and
      23.8%. Our selection of the risk-free interest rate was based on published
      yields for United States government securities with comparable terms.
      Because Targa Investments is a non-public company, its expected stock
      price volatility was estimated based upon the historical price volatility
      of the Dow Jones MidCap Pipelines Index over a period equal to the
      expected average term of the options granted. The calculated fair value of
      options granted during the years ended December 31, 2008, 2007, and
      2006 was $1.48, $0.63 and $0.21 per
share.


(3)
            For
      2008 “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.


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Name
                      
                      401(k)
      and Profit Sharing Plan
                      
                      
                      Dollar
      Value of Life Insurance
                      
                      
                      TotalRene
      R. Joyce
                      
                      $
                      18,400
                      
                      
                      $
                      805
                      
                      
                      $
                      19,205Jeffrey
      J. McParland
                      
                      
                      18,400
                      
                      
                      
                      631
                      
                      
                      
                      19,031Joe
      Bob Perkins
                      
                      
                      18,400
                      
                      
                      
                      724
                      
                      
                      
                      19,124James
      W. Whalen
                      
                      
                      18,400
                      
                      
                      
                      471
                      
                      
                      
                      18,871Michael
      A. Heim
                      
                      
                      18,400
                      
                      
                      
                      671
                      
                      
                      
                      19,071








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 2008:








Grants
      of Plan Based Awards for 2008Estimated
      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 OptionAwards(3)Name
                      
                      GrantDate
                      
                      
                      Threshold
                      
                      
                      Target
                      
                      
                      2X Target
                      
                      Threshold
                      
                      Target(Units)
                      
                      MaximumMr.
      Joyce
                      
                      
                      N/A
                      
                      
                      $
                      82,500
                      
                      
                      $
                      165,000
                      
                      
                      $
                      330,00001/17/08
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      4,000
                      
                      
                      
                      $
                      148,400Mr.
      McParland
                      
                      
                      N/A
                      
                      
                      
                      58,750
                      
                      
                      
                      117,500
                      
                      
                      
                      259,00001/17/08
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      2,700
                      
                      
                      
                      
                      100,170Mr.
      Perkins
                      
                      
                      N/A
                      
                      
                      
                      74,250
                      
                      
                      
                      148,500
                      
                      
                      
                      297,00001/17/08
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      3,500
                      
                      
                      
                      
                      129,850Mr.
      Whalen
                      
                      
                      N/A
                      
                      
                      
                      74,250
                      
                      
                      
                      148,500
                      
                      
                      
                      297,00001/17/08
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      3,500
                      
                      
                      
                      
                      129,850Mr.
      Heim
                      
                      
                      N/A
                      
                      
                      
                      68,750
                      
                      
                      
                      137,500
                      
                      
                      
                      275,00001/17/08
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      3,500
                      
                      
                      
                      
                      129,850


_____





(1)
            These
      awards were granted under the Bonus Plan. At the time the Bonus Plan was
      adopted, the estimated future payouts in the above table under the heading
      “Estimated Possible Payouts Under Non-Equity Incentive Plan Awards”
      represented the cash bonus pool available for awards to the named
      executive officers under the Bonus
Plan.


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


(3)
            The
      dollar amounts shown are determined by multiplying the number of units
      reported in the table by $37.10 (the per unit fair value under SFAS 123(R)
      on the grant date) and assume full payout under the awards at the time of
      vesting.





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





A
discussion of 2008 salaries, bonuses and incentive plans is included in
“— Compensation Discussion and Analysis.”





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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 2008 Fiscal Year-End”
below.





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 2008 Fiscal Year-End” below.





Outstanding
Equity Awards at 2008 Fiscal Year-End





Targa
Investments indirectly owns all of our 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, 2008 for each of our named executive officers.





Outstanding
      Equity Awards at 2008 Fiscal Year-EndOption
      Awards
                                  
                                  Stock
      AwardsName
                                  
                                  #
      Exercisable
                                  
                                  
                                  #
      Unexercisable
                                  
                                  
                                  Option
      Exercise Price
                                  
                                  Option
      Expiration Date
                                  
                                  Number
      of Shares of Stock That Have Not Vested
                                  
                                  
                                  Market
      Value of Shares of Stock That Have Not Vested(7)
                                  
                                  
                                  Equity
      Incentive Plan Awards: Number of Unearned Performance Units That Have
      Not Vested(8)
                                  
                                  
                                  Equity
      Incentive Plan Awards: Market or Payout Value of Unearned Performance
      Units That Have Not Vested(9)Rene
      R. Joyce
                                  
                                  
                                  17,417
                                  
                                  
                                  
                                  4,355
                                  (1
                                  )
                                  
                                  $
                                  0.75
                                  
                                  10/31/15
                                  
                                  
                                  146,840
                                  (4
                                  )
                                  
                                  $
                                  132,156
                                  
                                  
                                  
                                  19,000
                                  
                                  
                                  $
                                  194,962233,101
                                  
                                  
                                  
                                  58,275
                                  (1
                                  )
                                  
                                  
                                  3.00
                                  
                                  10/31/15
                                  
                                  
                                  1,423
                                  (5
                                  )
                                  
                                  
                                  1,281197,239
                                  
                                  
                                  
                                  49,310
                                  (1
                                  )
                                  
                                  
                                  15.00
                                  
                                  10/31/152,405
                                  
                                  
                                  
                                  601
                                  (2
                                  )
                                  
                                  
                                  3.00
                                  
                                  12/20/152,047
                                  
                                  
                                  
                                  512
                                  (2
                                  )
                                  
                                  
                                  15.00
                                  
                                  12/20/15Jeffrey
      J. McParland
                                  
                                  
                                  17,417
                                  
                                  
                                  
                                  4,355
                                  (1
                                  )
                                  
                                  
                                  0.75
                                  
                                  10/31/15
                                  
                                  
                                  111,024
                                  (4
                                  )
                                  
                                  
                                  99,922
                                  
                                  
                                  
                                  10,900
                                  
                                  
                                  
                                  111,505174,825
                                  
                                  
                                  
                                  43,707
                                  (1
                                  )
                                  
                                  
                                  3.00
                                  
                                  10/31/15
                                  
                                  
                                  1,067
                                  (5
                                  )
                                  
                                  
                                  960147,929
                                  
                                  
                                  
                                  36,983
                                  (1
                                  )
                                  
                                  
                                  15.00
                                  
                                  10/31/151,803
                                  
                                  
                                  
                                  451
                                  (2
                                  )
                                  
                                  
                                  3.00
                                  
                                  12/20/151,535
                                  
                                  
                                  
                                  384
                                  (2
                                  )
                                  
                                  
                                  15.00
                                  
                                  12/20/15Joe
      Bob Perkins
                                  
                                  
                                  17,417
                                  
                                  
                                  
                                  4,355
                                  (1
                                  )
                                  
                                  
                                  0.75
                                  
                                  10/31/15
                                  
                                  
                                  122,336
                                  (4
                                  )
                                  
                                  
                                  110,102
                                  
                                  
                                  
                                  14,300
                                  
                                  
                                  
                                  146,322188,811
                                  
                                  
                                  
                                  47,203
                                  (1
                                  )
                                  
                                  
                                  3.00
                                  
                                  10/31/15
                                  
                                  
                                  1,153
                                  (5
                                  )
                                  
                                  
                                  1,038159,765
                                  
                                  
                                  
                                  39,940
                                  (1
                                  )
                                  
                                  
                                  15.00
                                  
                                  10/31/151,949
                                  
                                  
                                  
                                  486
                                  (2
                                  )
                                  
                                  
                                  3.00
                                  
                                  12/20/151,658
                                  
                                  
                                  
                                  415
                                  (2
                                  )
                                  
                                  
                                  15.00
                                  
                                  12/20/15James
      W. Whalen
                                  
                                  
                                  45,454
                                  
                                  
                                  
                                  45,454
                                  (3
                                  )
                                  
                                  
                                  3.00
                                  
                                  11/01/15
                                  
                                  
                                  101,139
                                  (6
                                  )
                                  
                                  
                                  91,026
                                  
                                  
                                  
                                  14,300
                                  
                                  
                                  
                                  146,322153,847
                                  
                                  
                                  
                                  38,461
                                  (3
                                  )
                                  
                                  
                                  15.00
                                  
                                  11/01/15
                                  
                                  
                                  1,110
                                  (5
                                  )
                                  
                                  
                                  999469
                                  
                                  
                                  
                                  468
                                  (2
                                  )
                                  
                                  
                                  3.00
                                  
                                  12/20/151,597
                                  
                                  
                                  
                                  399
                                  (2
                                  )
                                  
                                  
                                  15.00
                                  
                                  12/20/15Michael
      A. Heim
                                  
                                  
                                  17,417
                                  
                                  
                                  
                                  4,355
                                  (1
                                  )
                                  
                                  
                                  0.75
                                  
                                  10/31/15
                                  
                                  
                                  122,336
                                  (4
                                  )
                                  
                                  
                                  110,102
                                  
                                  
                                  
                                  13,500
                                  
                                  
                                  
                                  137,971188,811
                                  
                                  
                                  
                                  47,203
                                  (1
                                  )
                                  
                                  
                                  3.00
                                  
                                  10/31/15
                                  
                                  
                                  1,153
                                  (5
                                  )
                                  
                                  
                                  1,038159,765
                                  
                                  
                                  
                                  39,940
                                  (1
                                  )
                                  
                                  
                                  15.00
                                  
                                  10/31/151,949
                                  
                                  
                                  
                                  486
                                  (2
                                  )
                                  
                                  
                                  3.00
                                  
                                  12/20/151,658
                                  
                                  
                                  
                                  415
                                  (2
                                  )
                                  
                                  
                                  15.00
                                  
                                  12/20/15


__________


(1)
            Represents
      options to purchase shares of Targa Investments common stock awarded on
      October 31, 2005. These options vest on October 31,
      2009.


(2)
            Represents
      options to purchase shares of Targa Investments common stock awarded on
      December 20, 2005. These options vest on December 20,
      2009.


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(3)
            Represents
      options to purchase shares of Targa Investments common stock awarded on
      November 1, 2005. These options vest on November 1,
      2009.


(4)
            Represents
      shares of restricted common stock of Targa Investments awarded on
      October 31, 2005. These shares vest on October 31,
      2009.


(5)
            Represents
      shares of restricted common stock of Targa Investments awarded on
      December 20, 2005. These shares vest on December 20,
      2009.


(6)
            Represents
      shares of restricted common stock of Targa Investments awarded on
      October 31, 2005 (544 shares) and November 1, 2005
      (100,595 shares). These shares vest on October 31, 2009 (with
      respect to the October 31, 2005 awards) and November 1, 2009
      (with respect to the November 1, 2005
  awards).


(7)
            The
      dollar amounts shown are determined by multiplying the number of shares or
      units reported in the table by $0.90(the value
      determined by an independent consultant pursuant to a valuation of Targa
      Investments’ common stock as of December 31, 2008), which management
      believes is a reasonable approximation of the value of such stock as of
      December 31, 2008.


(8)
            Represents
      the number of performance units awarded on February 8, 2007 and
      January 17, 2008 under the Targa Investments Long-Term Incentive Plan.
      These awards vest in August 2010 and June 2011, respectively, 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.”


(9)
            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, 2008
      ($7.75) and the related distribution equivalent rights for each award
      and assume full payout under the awards at the time of
      vesting.





Option
Exercises and Stock Vested in 2008





The
following table provides the amount realized during 2008 by each named executive
officer upon the exercise of options and upon the vesting of restricted common
stock.











Option Exercises and Stock Vested for
      2008Option Awards
                          
                          
                          Stock AwardsName
                          
                          Number
      of Shares Acquired onExercise(1)
                          
                          
                          Value
      Realizedon Exercise
                          
                          
                          Number
      of Shares Acquired onVesting
                          
                          
                          Value
      Realizedon
Vesting(6)Rene
      R. Joyce
                          
                          
                          
                          
                          
                          
                          
                          
                          677,162
                          (2
                          )
                          
                          $
                          2,537,948Jeffrey
      J. McParland
                          
                          
                          
                          
                          
                          
                          
                          
                          517,456
                          (3
                          )
                          
                          
                          1,937,667Joe
      Bob Perkins
                          
                          
                          
                          
                          
                          
                          
                          
                          578,065
                          (4
                          )
                          
                          
                          2,162,061James
      W. Whalen
                          
                          
                          137,772
                          
                          
                          $
                          475,313
                          
                          
                          
                          127,389
                          (5
                          )
                          
                          
                          700,227Michael
      A. Heim
                          
                          
                          
                          
                          
                          
                          
                          
                          
                          
                          578,065
                          (4
                          )
                          
                          
                          2,162,061





__________





(1)
            At
      the time of exercise of the stock options, the common stock acquired upon
      exercise had a value of $3.45 per share. This value was determined by an
      independent consultant pursuant to a valuation of Targa Investments common
      stock as of October 24, 2007.


(2)
            The
      shares vested as follows: 67,288 shares on January 2, 2008, 16,822 shares
      on April 16, 2008, 513,939 shares on April 30, 2008, 4,981 shares on June
      20, 2008, 73,420 shares on October 31, 2008 and 712 shares on
      December 20, 2008.


(3)
            The
      shares vested as follows: 55,272 shares on January 2, 2008, 13,818 shares
      on April 16, 2008, 388,584 shares on April 30, 2008, 3,736 shares on June
      20, 2008, 55,512 shares on October 31, 2008 and 534 shares on
      December 20, 2008


(4)
            The
      shares vested as follows: 67,288 shares on January 2, 2008, 16,822 shares
      on April 16, 2008, 428,176 shares on April 30, 2008, 4,035 shares on June
      20, 2008, 61,168 shares on October 31, 2008 and 576 shares on
      December 20, 2008.


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(5)
            The
      shares vested as follows: 20,112 shares on January 2, 2008, 5,028 shares
      on April 16, 2008, 544 shares on October 31, 2008, 100,595 shares on
      November 1, 2008 and 1,110 shares on  December 20,
      2008.


(6)
            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 2008 and 2007, which management believes are
      reasonable approximations of the value of such stock as of the applicable
      dates.





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 stock (both vested and
unvested) granted to him under the Stock Agreement is forfeited to Targa
Investments for no consideration. For one year 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.





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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 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;


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•
            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.





The
following table reflects payments that 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, 2008.





Name
                              
                              Change of Control
                              
                              
                              Termination for Death or
      DisabilityRene
      R. Joyce
                              
                              $
                              134,090
                              (1
                              )
                              
                              $
                              134,090
                              (1
                              )Jeffrey
      J. McParland
                              
                              
                              101,535
                              (2
                              )
                              
                              
                              101,535
                              (2
                              )Joe
      Bob Perkins
                              
                              
                              111,793
                              (3
                              )
                              
                              
                              111,793
                              (3
                              )James
      W. Whalen
                              
                              
                              92,025
                              (4
                              )
                              
                              
                              92,025
                              (4
                              )Michael
      A. Heim
                              
                              
                              111,793
                              (5
                              )
                              
                              
                              111,793
                              (5
                              )


__________


(1)
            Of
      this amount, $132,156 relates to the unvested shares of restricted stock
      of Targa Investments granted on October 31, 2005; $1,281 relates to
      the unvested shares of restricted stock of Targa Investments granted on
      December 20, 2005; and $653 relates to the unvested options to
      purchase Targa Investments common stock granted on October 31,
      2005.


(2)
            Of
      this amount, $99,922 relates to the unvested shares of restricted stock of
      Targa Investments granted on October 31, 2005; $960 relates to the
      unvested shares of restricted stock of Targa Investments granted on
      December 20, 2005; and $653 relates to the unvested options to
      purchase Targa Investments common stock granted on October 31,
      2005.


(3)
            Of
      this amount, $110,102 relates to the unvested shares of restricted stock
      of Targa Investments granted on October 31, 2005; $1,038 relates to
      the unvested shares of restricted stock of Targa Investments granted on
      December 20, 2005; $653 relates to the unvested options to purchase
      Targa Investments common stock granted on October 31,
      2005.


(4)
            Of
      this amount, $490 relates to the unvested shares of restricted stock of
      Targa Investments granted on October 31, 2005; $90,536 relates to the
      unvested shares of restricted stock of Targa Investments granted on
      November 1, 2005; and $999 relates to the unvested shares of
      restricted stock of Targa Investments granted on December 20,
      2005.


(5)
            Of
      this amount, $110,102 relates to the unvested shares of restricted stock
      of Targa Investments granted on October 31, 2005; $1,038 relates to
      the unvested shares of restricted stock of Targa Investments granted on
      December 20, 2005;  and $653 relates to the unvested
      options to purchase Targa Investments common stock granted on
      October 31, 2005.





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.


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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: (i) 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.





•
            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.








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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, 2008.





Name
                              
                              Change of Control
                              
                              
                              Termination for Death or
      DisabilityRene
      R. Joyce
                              
                              $
                              194,962
                              (1
                              )
                              
                              $
                              194,962
                              (1
                              )Jeffrey
      J. McParland
                              
                              
                              111,505
                              (2
                              )
                              
                              
                              111,505
                              (2
                              )Joe
      Bob Perkins
                              
                              
                              146,322
                              (3
                              )
                              
                              
                              146,322
                              (3
                              )James
      W. Whalen
                              
                              
                              146,322
                              (3
                              )
                              
                              
                              146,322
                              (3
                              )Michael
      A. Heim
                              
                              
                              137,971
                              (4
                              )
                              
                              
                              137,971
                              (4
                              )


_______


(1)
            Of
      this amount, $116,250 and $40,332 relate to the performance units and
      related distribution equivalent rights granted on February 7, 2007,
      respectively; and $31,000 and $7,380 relate to the performance units and
      related distribution equivalent rights granted on January 17, 2008,
      respectively.


(2)
            Of
      this amount, $63,550 and $22,048 relate to the performance units and
      related distribution equivalent rights granted on February 7, 2007,
      respectively; and $20,925 and $4,982 relate to the performance units and
      related distribution equivalent rights granted on January 17, 2008,
      respectively.


(3)
            Of
      this amount, $83,700 and $29,039 relate to the performance units and
      related distribution equivalent rights granted on February 7, 2007,
      respectively; and $27,125 and $6,458 relate to the performance units and
      related distribution equivalent rights granted on January 17, 2008,
      respectively.


(4)
            Of
      this amount, $77,500 and $26,888 relate to the performance units and
      related distribution equivalent rights granted on February 7, 2007,
      respectively; and $27,125 and $6,458 relate to the performance units and
      related distribution equivalent rights granted on January 17, 2008,
      respectively.





The
following table reflects the aggregate payments that would have been made to
each of the named executive officers under the 2005 Incentive Plan, 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,
2008.





Name
                  
                  Change of Control
                  
                  
                  Termination for Death or
      DisabilityRene
      R. Joyce
                  
                  $
                  329,052
                  
                  
                  $
                  329,052Jeffrey
      J. McParland
                  
                  
                  213,040
                  
                  
                  
                  213,040Joe
      Bob Perkins
                  
                  
                  258,115
                  
                  
                  
                  258,115James
      W. Whalen
                  
                  
                  238,347
                  
                  
                  
                  238,347Michael
      A. Heim
                  
                  
                  249,764
                  
                  
                  
                  249,764








Director
Compensation





The
following table sets forth the compensation earned by our non-employee directors
for 2008:





Name
                
                Fees Earned or Paid in Cash
                
                
                Stock Awards ($)(1)
                
                
                All Other Compensation(4)
                
                
                Total CompensationRobert
      B. Evans (2) (3)
                
                $
                64,000
                
                
                $
                34,939
                
                
                $
                6,585
                
                
                $
                105,524Chansoo
      Joung (2) (3)
                
                
                49,000
                
                
                
                34,939
                
                
                
                6,585
                
                
                
                90,524Peter
      R. Kagan (2) (3)
                
                
                49,000
                
                
                
                34,939
                
                
                
                6,585
                
                
                
                90,524Barry
      R. Pearl (2) (3)
                
                
                84,000
                
                
                
                34,939
                
                
                
                6,585
                
                
                
                125,524William
      D. Sullivan (2) (3)
                
                
                58,000
                
                
                
                34,939
                
                
                
                6,585
                
                
                
                99,524


__________


(1)
            Amounts
      represent expense recognized for financial statement reporting purposes in
      accordance with SFAS 123(R) with respect to stock awards for fiscal year
      2008, disregarding any estimate of forfeitures related to service-based
      vesting conditions. No stock awards granted to the directors were
      forfeited during 2008.  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 the Notes to Consolidated
      Financial Statements at Note 8 included in this Annual
      Report.


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(2)
            Messrs. Evans,
      Joung, Kagan, Pearl and Sullivan each received 2,000 common units of the
      Partnership on March 25, 2008 in connection with their service on the
      Board of Directors of the Partnership’s general partner. The grant date
      fair value of the 2,000 common units granted to each of these named
      individuals was $22.86, based on the closing price of the common units on
      the day prior to the grant date.During 2008, each
      of the directors received $6,585 in distributions on the common units of
      the Partnership that were awarded to them. The Partnership also recognized
      $6,585 of expense for each of the stock awards held by Messrs. Joung and
      Kagan.


(3)
            As
      of December 31, 2008, Mr. Evans held 13,900 common units,
      Mr. Joung and Kagan each held 4,000 common units, Mr. Pearl held
      6,300 common units and Mr. Sullivan held 8,700 common units of the
      Partnership.


(4)
            For
      2008 “All Other Compensation” consists of the distributions paid on common
      units of the Partnership from unit
awards.





Narrative
      to Director Compensation Table





For 2008,
each independent director receives an annual cash retainer of $34,000 and the
chairman of the Audit Committee receives 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 March
2008 to the General Partners’ nonmanagement 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
initial award of 2,000 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.





Changes
for 2009





Director Long-term Equity
Incentives.  In January 2009, each of the General Partners’
nonmanagement and independent directors received an award of 4,000 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
Ownershipof Certain Beneficial Owners and Management and Related
Stockholder


Matters





The
following table sets forth the beneficial ownership of our units as of February
25, 2009 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.


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Targa
      Resources Partners LP
                          
                          
                          Targa
      Resources Investments Inc.Name of Beneficial Owner
(1)
                          
                          Common Units Beneficially
    Owned
                          
                          
                          Percentage of Common Units Beneficially
      Owned
                          
                          
                          Subordinated Units Beneficially Owned
      (6)
                          
                          
                          Percentage of Subordinated Units Beneficially
      Owned
                          
                          
                          Percentage of Total Common and Subordinated 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. (2)
                          
                          
                          -
                          
                          
                          
                          *
                          
                          
                          
                          11,528,231
                          
                          
                          
                          100.00
                          %
                          
                          
                          24.9
                          %
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          
                          -
                          
                          
                          
                          -Lehman
      Brothers Holdings Inc. (3)
                          
                          
                          2,619,219
                          
                          
                          
                          7.6
                          %
                          
                          
                          
                          
                          
                          
                          
                          
                          
                          
                          5.7
                          %
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          
                          -
                          
                          
                          
                          -LaBranche
      Structured Products LLC (4)
                          
                          
                          2,510,920
                          
                          
                          
                          7.2
                          %
                          
                          
                          
                          
                          
                          
                          
                          
                          
                          
                          5.4
                          %
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          
                          -
                          
                          
                          
                          -Rene
      R. Joyce
                          
                          
                          81,000
                          
                          
                          
                          *
                          
                          
                          
                          295,678
                          
                          
                          
                          2.56
                          %
                          
                          
                          *
                          
                          
                          
                          56,208
                          
                          
                          
                          1,277,634
                          (7
                          )
                          
                          
                          *
                          
                          
                          
                          15.9
                          %Joe
      Bob Perkins
                          
                          
                          32,100
                          
                          
                          
                          *
                          
                          
                          
                          248,996
                          
                          
                          
                          2.16
                          %
                          
                          
                          *
                          
                          
                          
                          47,632
                          
                          
                          
                          1,071,154
                          (8
                          )
                          
                          
                          *
                          
                          
                          
                          13.5
                          %Michael
      A. Heim
                          
                          
                          8,000
                          
                          
                          
                          *
                          
                          
                          
                          235,415
                          
                          
                          
                          2.04
                          %
                          
                          
                          *
                          
                          
                          
                          39,192
                          
                          
                          
                          1,071,154
                          (8
                          )
                          
                          
                          *
                          
                          
                          
                          13.5
                          %Jeffrey
      J. McParland
                          
                          
                          16,500
                          
                          
                          
                          *
                          
                          
                          
                          209,512
                          
                          
                          
                          1.82
                          %
                          
                          
                          *
                          
                          
                          
                          32,856
                          
                          
                          
                          973,056
                          (9
                          )
                          
                          
                          *
                          
                          
                          
                          12.3
                          %James
      W. Whalen
                          
                          
                          111,152
                          
                          
                          
                          *
                          
                          
                          
                          165,365
                          
                          
                          
                          1.43
                          %
                          
                          
                          *
                          
                          
                          
                          14,978
                          
                          
                          
                          875,525
                          (10
                          )
                          
                          
                          *
                          
                          
                          
                          11.3
                          %Chansoo
      Joung (5)
                          
                          
                          8,000
                          
                          
                          
                          *
                          
                          
                          
                          -
                          
                          
                          
                          *
                          
                          
                          
                          *
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          
                          -
                          
                          
                          
                          -Peter
      R. Kagan (5)
                          
                          
                          8,000
                          
                          
                          
                          *
                          
                          
                          
                          -
                          
                          
                          
                          *
                          
                          
                          
                          *
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          
                          -
                          
                          
                          
                          -Robert
      B. Evans
                          
                          
                          17,900
                          
                          
                          
                          *
                          
                          
                          
                          -
                          
                          
                          
                          *
                          
                          
                          
                          *
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          
                          -
                          
                          
                          
                          -Barry
      R. Pearl
                          
                          
                          10,300
                          
                          
                          
                          *
                          
                          
                          
                          -
                          
                          
                          
                          *
                          
                          
                          
                          *
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          
                          -
                          
                          
                          
                          -William
      D. Sullivan
                          
                          
                          12,700
                          
                          
                          
                          *
                          
                          
                          
                          -
                          
                          
                          
                          *
                          
                          
                          
                          *
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          
                          -
                          
                          
                          
                          -All
      directors and executive officers
                            as
      a group  (12 persons)
                          
                          
                          292,252
                          
                          
                          
                          *
                          
                          
                          
                          1,551,157
                          
                          
                          
                          13.46
                          %
                          
                          
                          4.0
                          %
                          
                          
                          241,114
                          
                          
                          
                          7,226,752
                          (11
                          )
                          
                          
                          3.8
                          %
                          
                          
                          72.6
                          %


_________________________________


*           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 equitysecurities is sole voting and
      investment power.


(2)
            The
      units attributed to Targa Resources Investments Inc. are held by two
      indirect wholly-owned subsidiaries, Targa GP Inc. and Targa LP
      Inc.


(3)
            Lehman
      Brothers Holdings Inc. beneficially owns 1,775,219 common units, of which
      Lehman Brothers Inc. beneficially owns 1,295,919 common units (which
      includes 805,919 common unitsdirectly held by Lehman Brothers Inc. and
      490,000 common units directly held by Lehman Brothers MLP Partners LP) and
      Lehman Brothers MLP Opportunity Fund LP beneficially owns 479,300
      common units. Lehman Brothers Inc. is wholly-owned by Lehman Brothers
      Holdings Inc. The address for Lehman Brothers Holdings Inc. and its
      affiliates is 745 Seventh Avenue, New York, New
      York 10019.


(4)
            LaBranche
      Structured Products LLC beneficially owns 2,510,920 common units. The
      address for LaBranche Structured Products LLC is 33 Whitehall Street, New
      York, New York 10004.


(5)
            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
      approximately 79% 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 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 466
      Lexington Avenue, New York, New York 10017. Messrs. Kagan and Joung,
      directors of Targa Resources Partners LP, 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.


(6)
            The
      subordinated units of the Partnership presented as being beneficially
      owned by our directors and executive officers represent the number of
      units held indirectly by Targa Resources Investments Inc. that are
      attributable to such directors and officers based on their ownership of
      equity interests in Targa Resources Investments Inc. Targa
      Resources Investments Inc. indirectly holds all 11,528,231
      subordinated units of the
Partnership.


(7)
            Of
      this amount, 452,209 shares of restricted common stock reflect options
      that are currently exercisable for shares of restricted common
      stock.


(8)
            Of
      this amount, 369,600 shares of restricted common stock reflect options
      that are currently exercisable for shares of restricted common
      stock.


(9)
            Of
      this amount, 321,770 shares of restricted common stock reflect options
      that are currently exercisable for shares of restricted common
      stock.


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(10)
            Of
      this amount, 343,509 shares of restricted common stock reflect options
      that are currently exercisable for shares of restricted common
      stock.


(11)
            Of
      this amount, 2,385,143 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, 2008 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,
      warrantsand 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 incolumn (a))(a)
                
                
                (b)
                
                
                (c)Equity
      compensation plans approved by security holders
                
                
                -
                
                
                $
                -
                
                
                
                1,648,000Equity
      compensation plans not approved by security holders
                
                
                -
                
                
                
                -
                
                
                
                -Total
                
                
                -
                
                
                $
                -
                
                
                
                1,648,000







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





Our
general partner and its affiliates own 11,528,231 subordinated units
representing an aggregate 24.5% limited partner interest in us. In addition, our
general partner owns a 2% general partner interest in us and the incentive
distribution rights.





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Distributions
and Payments to Our General Partner and its Affiliates





The
following table summarizes the distributions and payments made by us to our
general partner and its affiliates in connection with our formation and to be
made to us by 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 affiliates, as the holders of11,528,231
      subordinated 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 $1.3 million on theirgeneral
      partner units and $15.6 million on theirsubordinated
      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.





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





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Agreements
Governing the Transactions





We and
other parties entered into the various documents and agreements that effected
our initial IPO transactions in February 2007 and the October 2007 offering
transactions, including the vesting of assets in and the assumption of
liabilities by, us and our subsidiaries and the application of the proceeds of
the IPO and the October 2007 offering. 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 the proceeds of the IPO and the October 2007
offering.





Purchase
and Sale Agreement





On
September 18, 2007, we entered into a purchase and sale agreement (the “Purchase
Agreement”) with Targa pursuant to which we acquired the SAOU and LOU Systems
for aggregate consideration of $705 million, subject to certain adjustments,
consisting of $697.6 million in cash and the issuance to our general partner of
275,511 general partner units, enabling our general partner to maintain its
general partner interest in us. On September 25 and 26, 2007, Targa completed
transactions that terminated certain out of the money NGL hedges associated with
the SAOU and LOU Systems and entered into new hedges for approximately the same
volume and term at then current market prices. Pursuant to the Purchase
Agreement, these hedging transactions resulted in a $24.2 million increase to
the purchase price we paid to Targa for the SAOU and LOU Systems. Pursuant to
the Purchase Agreement, Targa agreed to indemnify us from and against (i) all
losses that we incur arising from any breach of Targa’s representations,
warranties or covenants in the Purchase Agreement, (ii) certain environmental
matters and (iii) certain litigation matters. We agreed to indemnify Targa from
and against all losses that it incurs arising from or out of (i) the business or
operations of Targa Resources Texas GP LLC, Targa Texas, Targa Louisiana and
Targa Louisiana Intrastate LLC (whether relating to periods prior to or after
the closing of the acquisition of the SAOU and LOU Systems) to the extent such
losses are not matters for which Targa has indemnified us or (ii) any breach of
our representations, warranties or covenants in the Purchase Agreement. Certain
of Targa’s indemnification obligations are subject to an aggregate deductible of
$10 million and a cap equal to $80 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 October 24,
2007.





On
November 20, 2007, after the underwriters of the October 2007 offering exercised
their option to purchase additional shares, we settled with Targa their purchase
of an additional 37,062 general partner units allowing Targa to maintain its 2%
general partner interest in us. In December 2007, the adjustments to the
purchase price of the SAOU and LOU Systems resulted in an additional $0.8
million being paid to Targa.





Omnibus
Agreement





Concurrently
with the closing of the acquisition of the SAOU and LOU Systems, we amended and
restated our Omnibus Agreement (as amended and restated, the “Omnibus
Agreement”) 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. 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 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 are capped at $5 million annually for
      three years ending February 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


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·
            operations
      and certain direct expenses, which are not subject to the $5 million cap
      for general and administrative
expenses.





With
respect to the SAOU and LOU Systems, we will reimburse Targa for the following
expenses:





·
            general
      and administrative expenses, which are not capped, allocated to the SAOU
      and LOU systems according to Targa’s allocation practice;
    and





·
            operating
      and certain direct expenses, which are not
  capped.





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.





General
and administrative costs will continue to be allocated to the SAOU and LOU
Systems according to Targa’s allocation practice.





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, Targa indemnifies us until February 14, 2010 against certain
potential environmental claims, losses and expenses associated with the
operation of the North Texas System and occurring before February 14, 2007 that
are not reserved on the books of the Predecessor Business of the North Texas
System as of February 14, 2007. Targa’s maximum liability for this
indemnification obligation does not exceed $10.0 million and Targa does not have
any obligation under this indemnification until our aggregate losses exceed
$250,000. We have agreed to indemnify Targa against environmental liabilities
related to the North Texas System arising or occurring after the closing date of
this offering.





Additionally,
Targa indemnifies us for losses attributable to rights-of-way, certain consents
or governmental permits, preclosing litigation relating to the North Texas
System and income taxes 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 these
indemnifications until our aggregate losses exceed $250,000. We will indemnify
Targa for all losses attributable to the post-IPO operations of the North Texas
System. Targa’s obligations under this additional indemnification survive until
February 14, 2010, except that the indemnification for income tax liabilities
will terminate upon the expiration of the applicable statute of
limitations.





Contracts
with Affiliates





NGL and Condensate Purchase
Agreement for the North Texas System.We have entered into an NGL and
high pressure condensate purchase agreement pursuant to which (i) we are
obligated to sell all volumes of NGLs (other than high-pressure condensate) that
we own or control to Targa Liquids Marketing and Trade (“TLMT”) and (ii) we have
the right to sell to TLMT or third parties the volumes of high-pressure
condensate that we own or control, in each case at a price based on the
prevailing market price less transportation, fractionation and certain other
fees. This agreement has an initial term of 15 years and automatically extends
for a term of five years, unless the agreement is otherwise terminated by either
party. Furthermore, either party may elect to terminate the agreement if either
party ceases to be an affiliate of Targa.





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NGL Purchase Agreements for the SAOU
and LOU Systems.The SAOU System has entered into an NGL purchase
agreement pursuant to which it is obligated to sell all volumes of mixed NGLs or
raw product, which it owns or controls to TLMT at a price based on either TLMT’s
sales price to third parties or the prevailing market price, less
transportation, fractionation and certain other fees. The LOU System also has
entered into an NGL purchase agreement pursuant to which (i) it has the right to
sell to TLMT the volumes of raw product that it owns or controls at a
commercially reasonable price agreed by the parties and (ii) it is obligated to
sell all volumes of fractionated NGL components that it owns or controls at a
price based on TLMT’s sales price to third parties or the prevailing market
price, less transportation, fractionation and certain other fees. Both NGL
purchase agreements have an initial term of one year and automatically extend
for additional terms of one year, unless the agreements are otherwise terminated
by either party.





Natural Gas Purchase Agreements.Both the North Texas System and the SAOU and LOU Systems have entered
into market based natural gas purchase agreements. 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.





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
our subordinated 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.





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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.





See “Item
1. Business—Our Relationship with Targa Resources, Inc.” for information
regarding our relationship with Targa.







Relationships
with Warburg Pincus




Chansoo
Joung and Peter Kagan, two of the directors of Targa, are Managing Directors of
Warburg Pincus and are also directors of Broad Oak Energy, Inc. (“Broad Oak”)
from whom we buy natural gas and NGL products. Affiliates of Warburg Pincus own
a controlling interest in Broad Oak. We purchased $4.8 million of product from
Broad Oak during 2008. We had no commercial transactions prior to 2008 with
Broad Oak. These transactions were at market prices consistent with similar
transactions with nonaffiliated entities.




Relationships
with Noble Energy




Chris
Tong, one of the directors of Targa, is a Senior Vice President and Chief
Financial Officer of Noble Energy, Inc. (“Noble”) from whom we buy certain
commodity products. We had net purchases of $0.1 million, $0.1 million and $1.7
million of natural gas from Noble during 2008, 2007 and 2006.  These
transactions were at market prices consistent with similar transactions with
nonaffiliated entities.





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.


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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
NASDAQ Stock Market LLC 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
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 and Sullivan are independent as described in the rules of The
NASDAQ Stock Market LLC and the Exchange Act for purposes of serving on the
board of directors and the Audit Committee, respectively. Although the board of
directors of our general partner has made no formal determination as to the
independence of our other directors because we are not subject to majority
independence requirements, it is likely that Messrs. Kagan and Joung would be
determined to be independent for purposes of serving on the board of directors.
Messrs. Joyce, Whalen, Kagan and Joung would not be independent for purposes of
serving on the Audit Committee.








Item 14.Principal
AccountantFees and Services





We have
engaged PricewaterhouseCoopers LLP as our principal accountant. The following
table summarizes fees we were billed by PricewaterhouseCoopers for independent
auditing, tax and related services for each of the last two fiscal
years:








Year Ended December 31,2008
                
                
                2007(In
      thousands)Audit
      Fees (1)
                
                $
                1,219.6
                
                
                $
                2,267.5Tax
      Fees (2)
                
                
                534.2
                
                
                
                303.8All
      Other Fees (3)
                
                
                -
                
                
                
                -$
                1,753.8
                
                
                $
                2,571.3





_____________


(1) Audit
fees represent amounts billed for each of the years presented for professional
services rendered in connection with (i) the audit of our annual financial
statements, (ii) the review of our quarterly financial statements or (iii) those
services normally provided in connection with statutory and regulatory filings
or engagements including comfort letters, consents and other services related to
SEC matters. This information is presented as of the latest practicable date for
this Annual Report on Form 10-K.


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(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.





(3) All
other fees represent amounts we were billed in each of the years presented for
services not classifiable under the other categories listed in the table
above.





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 as our independent principal
accountant.







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)).




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)).


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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)).




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
            Registration
      Rights Agreement dated June 18, 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 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K
      filed June 18, 2008 (File No.
001-33303)).




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




10.2
            Commitment
      Increase Supplement, dated October 24, 2007, by and among Targa Resources
      Partners LP, Bank of America, N.A. and the parties signatory thereto as
      the Increasing Lenders and the New Lenders (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)).




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




10.4
            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
            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)).




10.6
            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)).




10.7
            Amended
      and Restated Omnibus Agreement, dated October 24, 2007, by and among Targa
      Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and
      Targa Resources GP LLC (incorporated by reference to Exhibit 10.5 to Targa
      Resources Partners LP’s Current Report on Form 8-K filed October 24, 2007
      (File No. 001-33303)).




10.8+
            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)).




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




10.10+*
            Amendment
      to Targa Resources Partners LP Long-Term Incentive Plan dated December 18,
      2008.


101
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10.11+
            Form
      of Restricted Unit Grant Agreement (incorporated by reference to Exhibit
      10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed
      October 24, 2007 (File No.
001-33303)).




10.12+*
            Form
      of Performance Unit Grant Agreement (incorporated by reference to Exhibit
      10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed
      January 28, 2009 (File No.
001-33303)).




10.13+*
            Targa
      Resources Investments Inc. 2008 Annual Incentive Compensation
      Plan




10.14+*
            Targa
      Resources Investments Inc. 2009 Annual Incentive Compensation
      Plan




10.15
            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)).




10.16
            Natural
      Gas Purchase Agreement, effective January 1, 2007, by and between Targa
      Gas Marketing LLC (Buyer) and Targa North Texas LP (Seller) (incorporated
      by reference to Exhibit 10.11 to Targa Resources Partners LP’s
      Registration Statement on Form S-1 filed October 1, 2007 (File No.
      333-146436)).




10.17
            NGL
      and Condensate Purchase Agreement, effective January 1, 2007, by and
      between Targa North Texas LP (Seller) and Targa Liquids Marketing and
      Trade (Buyer) (incorporated by reference to Exhibit 10.12 to Targa
      Resources Partners LP’s Registration Statement on Form S-1 filed October
      1, 2007 (File No. 333-146436)).




10.18
            Product
      Purchase Agreement, effective January 1, 2007, by and between Targa
      Louisiana Field Services LLC (Seller) and Targa Liquids Marketing and
      Trade (Buyer) (incorporated by reference to Exhibit 10.13 to Targa
      Resources Partners LP’s Registration Statement on Form S-1/A filed October
      12, 2007 (File No. 333-146436)).




10.19
            Raw
      Product Purchase Agreement, effective January 1, 2007, by and between
      Targa Texas Field Services LP (Seller) and Targa Liquids Marketing and
      Trade (Buyer) (incorporated by reference to Exhibit 10.14 to Targa
      Resources Partners LP’s Registration Statement on Form S-1/A filed October
      12, 2007 (File No. 333-146436)).




10.20
            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)).




10.21
            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)).




10.22
            Amended
      and Restated Natural Gas Purchase Agreement, effective December 1, 2005,
      by and between Targa Gas Marketing LLC (Buyer) and Targa Texas Field
      Services LP (Seller) (incorporated by reference to Exhibit 10.17 to Targa
      Resources Partners LP’s Registration Statement on Form S-1/A filed October
      12, 2007 (File No. 333-146436)).




10.23+
            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)).


102
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10.24+
            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)).




10.25+
            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)).




10.26
            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.




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.








103
 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:
February 26, 2009





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 February 26, 2009.





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 (PrincipalJohn
      Robert Sparger
                  
                  Accounting
      Officer)/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


104
 TABLE OF CONTENTS


INDEX TO FINANCIAL STATEMENTSTARGA
      RESOURCES PARTNERS LP AUDITED COMBINED CONSOLIDATED
    FINANCIALSTATEMENTSManagement’s Report on Internal Control Over Financial
      Reporting
                                                                                            F-2Report of Independent Registered Public Accounting
      Firm
                                                                                            F-3Consolidated Balance Sheets as of December 31, 2008
      and 2007
                                                                                            F-4Consolidated Statements of Operations for the
      Years Ended December 31, 2008, 2007 and 2006
                                                                                            F-5Consolidated Statements of Comprehensive Income (Loss) for the
      Years Ended December 31, 2008, 2007
      and 2006
                                                                                            F-6Consolidated Statement of Changes in Partners’
      Capital/Net Parent Investment for the Years Ended December
      31, 2008, 2007 and 2006
                                                                                            F-7Consolidated Statements of Cash Flows for the Years Ended
      December 31, 2008, 2007 and 2006
                                                                                            F-8Notes to Consolidated Financial
    Statements
                                                                                            F-9Note 1—Organization and
Operations
                                                                                            F-9Note 2—Basis of Presentation
                                                                                            F-9Note 3—Significant Accounting
      Policies
                                                                                            F-10Note 4—Property, Plant and Equipment
                                                                                            F-15Note 5—Asset Retirement Obligations
                                                                                            F-15Note 6—Debt Obligations
                                                                                            F-15Note 7—Partnership Equity and
      Distributions
                                                                                            F-18Note 8—Accounting for Unit-Based
      Compensation
                                                                                            F-20Note 9—Derivative Instruments and Hedging
      Activities
                                                                                            F-20Note 10—Related-Party Transactions
                                                                                            F-25Note 11—Commitments and
    Contingencies
                                                                                            F-28Note 12—Fair Value of Financial
      Instruments
                                                                                            F-29Note 13—Fair Value Measurements
                                                                                            F-29Note 14—Significant Risks and
    Uncertainties
                                                                                            F-30Note
      15—Selected Quarterly Financial Data
(Unaudited)
                                                                                            F-32





F-1
 TABLE OF CONTENTS


MANAGEMENT’SREPORTONINTERNAL CONTROL OVER FINANCIAL
REPORTING







The
management of Targa Resources GP LLC, the general partner of 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, 2008.







The
effectiveness of the Partnerships’s internal control over financial reporting as
of December 31, 2008 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, Chief Financial Officer


of
Targa Resources GP LLC, the general partner of


Targa Resources Partners
LP


(Principal Financial
Officer)







F-2
 TABLE OF CONTENTS





Report of Independent Registered Public Accounting
Firm





In our
opinion, theaccompanying
consolidated balance sheets and the related consolidated statements of
operations, of comprehensive income (loss), of changes in partners' capital/net
parent investment 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, 2008 and 2007, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 2008in 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, 2008, 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 inthe 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 was an integrated audit in 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 6 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





Houston,
Texas


February
25, 2009


F-3
 TABLE OF CONTENTS





TARGA
      RESOURCES PARTNERS LPCONSOLIDATED BALANCE SHEETSDecember 31,2008
                
                
                2007(In
      thousands)ASSETSCurrent
      assets:Cash
      and cash equivalents
                
                $
                81,768
                
                
                $
                50,994Receivables
      from third parties
                
                
                58,355
                
                
                
                59,346Receivables
      from affiliated companies
                
                
                22,295
                
                
                
                87,547Inventory
                
                
                987
                
                
                
                1,624Assets
      from risk management activities
                
                
                91,816
                
                
                
                8,695Other
      current assets
                
                
                289
                
                
                
                269Total
      current assets
                
                
                255,510
                
                
                
                208,475Property,
      plant and equipment, at cost
                
                
                1,492,726
                
                
                
                1,433,955Accumulated
      depreciation
                
                
                (248,389
                )
                
                
                (174,361
                )Property,
      plant and equipment, net
                
                
                1,244,337
                
                
                
                1,259,594Debt
      issue costs
                
                
                10,524
                
                
                
                6,588Long-term
      assets from risk management activities
                
                
                68,296
                
                
                
                3,040Other
      assets
                
                
                2,239
                
                
                
                2,275Total
      assets
                
                $
                1,580,906
                
                
                $
                1,479,972LIABILITIES
      AND PARTNERS' CAPITALCurrent
      liabilities:Accounts
      payable
                
                $
                8,649
                
                
                $
                5,693Accrued
      liabilities
                
                
                86,191
                
                
                
                142,836Liabilities
      from risk management activities
                
                
                11,664
                
                
                
                44,003Total
      current liabilities
                
                
                106,504
                
                
                
                192,532Long-term
      debt
                
                
                696,845
                
                
                
                626,300Long
      term liabilities from risk management activities
                
                
                9,679
                
                
                
                43,109Deferred
      income taxes
                
                
                1,959
                
                
                
                559Other
      long-term liabilities
                
                
                3,555
                
                
                
                3,266Commitments
      and contingencies (Note 11)Partners'
      capital:Common
      unitholders (34,652,000 and 34,636,000 units issued andoutstanding
      as of December 31, 2008 and 2007)
                
                
                769,921
                
                
                
                770,207Subordinated
      unitholders (11,528,231 units issued and outstanding as ofDecember
      31, 2008 and 2007)
                
                
                (85,185
                )
                
                
                (84,999
                )General
      partner (942,455 and 942,128 units issued and outstanding as
      ofDecember
      31, 2008 and 2007)
                
                
                5,556
                
                
                
                4,234Accumulated
      other comprehensive income (loss)
                
                
                72,072
                
                
                
                (75,236
                )Total
      partners' capital
                
                
                762,364
                
                
                
                614,206Total
      liabilities and partners' capital
                
                $
                1,580,906
                
                
                $
                1,479,972See
      notes to consolidated financial statements


F-4
 TABLE OF CONTENTS





TARGA
      RESOURCES PARTNERS LPCONSOLIDATED STATEMENTS OF
    OPERATIONSYear Ended December 31,2008
                
                
                2007
                
                
                2006(In
      thousands, except per unit amounts)Revenues
      from third parties
                
                $
                848,725
                
                
                $
                630,773
                
                
                $
                951,936Revenues
      from affiliates
                
                
                1,225,393
                
                
                
                1,030,696
                
                
                
                786,589Total
      operating revenues
                
                
                2,074,118
                
                
                
                1,661,469
                
                
                
                1,738,525Costs
      and expenses:Product
      purchases from third parties
                
                
                1,479,061
                
                
                
                1,215,733
                
                
                
                1,194,751Product
      purchases from affiliates
                
                
                323,970
                
                
                
                191,064
                
                
                
                322,917Operating
      expenses
                
                
                55,325
                
                
                
                50,931
                
                
                
                49,075Depreciation
      and amortization expense
                
                
                74,274
                
                
                
                71,756
                
                
                
                69,957General
      and administrative expense
                
                
                22,392
                
                
                
                18,927
                
                
                
                16,063Casualty
      loss
                
                
                167
                
                
                
                -
                
                
                
                -Gain
      on sale of assets
                
                
                (105
                )
                
                
                (296
                )
                
                
                -1,955,084
                
                
                
                1,548,115
                
                
                
                1,652,763Income
      from operations
                
                
                119,034
                
                
                
                113,354
                
                
                
                85,762Other
      income (expense):Interest
      expense, net
                
                
                (38,274
                )
                
                
                (21,998
                )
                
                
                -Interest
      expense allocated from Parent
                
                
                -
                
                
                
                (19,436
                )
                
                
                (88,025
                )Gain
      on debt extinguishment
                
                
                13,061
                
                
                
                -
                
                
                
                -Gain
      (loss) on mark-to-market derivative instruments
                
                
                (991
                )
                
                
                (30,221
                )
                
                
                16,756Other
                
                
                64
                
                
                
                30
                
                
                
                -Income
      before taxes
                
                
                92,894
                
                
                
                41,729
                
                
                
                14,493Deferred
      income tax expense
                
                
                (1,400
                )
                
                
                (1,479
                )
                
                
                (2,926
                )Net
      income
                
                
                91,494
                
                
                
                40,250
                
                
                $
                11,567Less:
      Net income allocable to predecessor operations
                
                
                -
                
                
                
                12,184Net
      income allocable to partners
                
                
                91,494
                
                
                
                28,066Net
      income attributable to general partner interests
                
                
                7,049
                
                
                
                561Net
      income available to limited partners
                
                $
                84,445
                
                
                $
                27,505Basic
      and diluted net income per limited partner unit
                
                $
                1.83
                
                
                $
                0.81Basic
      and diluted average limited partner units outstanding
                
                
                46,177
                
                
                
                34,002See
      notes to consolidated financial statements





F-5
 TABLE OF CONTENTS





TARGA
      RESOURCES PARTNERS LPCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
      (LOSS)Year Ended December 31,2008
                
                
                2007
                
                
                2006(In
      thousands)Net
      income
                
                $
                91,494
                
                
                $
                40,250
                
                
                $
                11,567Other
      comprehensive income (loss):Commodity
      hedges:Change
      in fair value
                
                
                130,002
                
                
                
                (105,584
                )
                
                
                36,937Reclassification
      adjustment for settled periods
                
                
                33,650
                
                
                
                993
                
                
                
                (822
                )Related
      income taxes
                
                
                -
                
                
                
                312
                
                
                
                (312
                )Interest
      rate hedges:Change
      in fair value
                
                
                (19,037
                )
                
                
                (1,689
                )
                
                
                1,267Reclassification
      adjustment for settled periods
                
                
                2,693
                
                
                
                (232
                )
                
                
                (488
                )Other
      comprehensive income (loss)
                
                
                147,308
                
                
                
                (106,200
                )
                
                
                36,582Comprehensive
      income (loss)
                
                $
                238,802
                
                
                $
                (65,950
                )
                
                $
                48,149See
      notes to consolidated financial statements





F-6
 TABLE OF CONTENTS





TARGA
      RESOURCES PARTNERS LPCONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL / NET
      PARENT INVESTMENTPartners'
      Capital
                    
                    
                    AccumulatedOtherLimited Partners
                    
                    
                    General
                    
                    
                    Comprehensive
                    
                    
                    Net
      ParentCommon
                    
                    
                    Subordinated
                    
                    
                    Partner
                    
                    
                    Income (Loss)
                    
                    
                    Investment
                    
                    
                    Total(In
      thousands)Balance,
      December 31, 2005
                    
                    $
                    -
                    
                    
                    $
                    -
                    
                    
                    $
                    -
                    
                    
                    $
                    (5,618
                    )
                    
                    $
                    286,841
                    
                    
                    $
                    281,223Distributions
      to Parent
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    (83,459
                    )
                    
                    
                    (83,459
                    )Net
      income
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    11,567
                    
                    
                    
                    11,567Other
      comprehensive income
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    36,582
                    
                    
                    
                    -
                    
                    
                    
                    36,582Balance,
      December 31, 2006
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    30,964
                    
                    
                    
                    214,949
                    
                    
                    
                    245,913Net
      income attributable to predecessor operations:For
      the period January 1, 2007 to February 13, 2007for
      North Texas
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    (6,861
                    )
                    
                    
                    (6,861
                    )For
      the period January 1, 2007 to October 23, 2007for
      SAOU/LOU
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    19,045
                    
                    
                    
                    19,045Net
      income attributable to post MLP ownership
                    
                    
                    19,063
                    
                    
                    
                    8,442
                    
                    
                    
                    561
                    
                    
                    
                    
                    
                    
                    
                    -
                    
                    
                    
                    28,066Other
      contributions associated with North Texas System
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    218,993
                    
                    
                    
                    218,993Other
      contributions associated with SAOU/LOU System
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    195,960
                    
                    
                    
                    195,960Book
      value of net assets contributed by Targa Resources, Inc.
                    
                    
                    -
                    
                    
                    
                    376,351
                    
                    
                    
                    20,554
                    
                    
                    
                    -
                    
                    
                    
                    (396,905
                    )
                    
                    
                    -Book
      value of net assets transferred via common controlfrom
      Targa Resources, Inc. to the Partnership
                    
                    
                    -
                    
                    
                    
                    232,420
                    
                    
                    
                    12,761
                    
                    
                    
                    -
                    
                    
                    
                    (245,181
                    )
                    
                    
                    -Distribution
      to Targa Resources, Inc. for assets transferredunder
      common control
                    
                    
                    -
                    
                    
                    
                    (692,486
                    )
                    
                    
                    (37,416
                    )
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    (729,902
                    )Issuance
      of units to public (including underwriterover-allotment),
      net of offering and other costs
                    
                    
                    771,835
                    
                    
                    
                    -
                    
                    
                    
                    8,398
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    780,233Amortization
      of equity awards
                    
                    
                    180
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    180Other
      comprehensive loss
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    (106,200
                    )
                    
                    
                    -
                    
                    
                    
                    (106,200
                    )Distributions
      to unitholders
                    
                    
                    (20,871
                    )
                    
                    
                    (9,726
                    )
                    
                    
                    (624
                    )
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    (31,221
                    )Balance,
      December 31, 2007
                    
                    
                    770,207
                    
                    
                    
                    (84,999
                    )
                    
                    
                    4,234
                    
                    
                    
                    (75,236
                    )
                    
                    
                    -
                    
                    
                    
                    614,206Contributions
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    8
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    8Amortization
      of equity awards
                    
                    
                    280
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    280Other
      comprehensive income
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    147,308
                    
                    
                    
                    -
                    
                    
                    
                    147,308Net
      income
                    
                    
                    63,362
                    
                    
                    
                    21,083
                    
                    
                    
                    7,049
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    91,494Distributions
      to unitholders
                    
                    
                    (63,928
                    )
                    
                    
                    (21,269
                    )
                    
                    
                    (5,735
                    )
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    (90,932
                    )Balance,
      December 31, 2008
                    
                    $
                    769,921
                    
                    
                    $
                    (85,185
                    )
                    
                    $
                    5,556
                    
                    
                    $
                    72,072
                    
                    
                    $
                    -
                    
                    
                    $
                    762,364See
      notes to consolidated financial statements





F-7
 TABLE OF CONTENTS





TARGA
      RESOURCES PARTNERS LPCONSOLIDATED STATEMENTS OF CASH FLOWSYear Ended December 31,2008
                  
                  
                  2007
                  
                  
                  2006(In
      thousands)Cash
      flows from operating activitiesNet
      income
                  
                  $
                  91,494
                  
                  
                  $
                  40,250
                  
                  
                  $
                  11,567Adjustments
      to reconcile net income to net cashprovided
      by operating activities:Amortization
      in interest expense
                  
                  
                  2,116
                  
                  
                  
                  1,805
                  
                  
                  
                  6,246Amortization
      in general and administrative expense
                  
                  
                  280
                  
                  
                  
                  180
                  
                  
                  
                  -Depreciation
      and other amortization expense
                  
                  
                  74,274
                  
                  
                  
                  71,756
                  
                  
                  
                  69,957Accretion
      of asset retirement obligations
                  
                  
                  231
                  
                  
                  
                  342
                  
                  
                  
                  245Deferred
      income tax expense
                  
                  
                  1,400
                  
                  
                  
                  1,479
                  
                  
                  
                  2,926Risk
      management activities
                  
                  
                  (63,973
                  )
                  
                  
                  30,751
                  
                  
                  
                  (18,297
                  )Gain
      on debt extinguishment
                  
                  
                  (13,061
                  )
                  
                  
                  -
                  
                  
                  
                  -Gain
      on sale of assets
                  
                  
                  (105
                  )
                  
                  
                  (296
                  )
                  
                  
                  -Changes
      in operating assets and liabilities:Receivables
      and other assets
                  
                  
                  63,698
                  
                  
                  
                  89,487
                  
                  
                  
                  79,573Inventory
                  
                  
                  637
                  
                  
                  
                  (666
                  )
                  
                  
                  1,373Accounts
      payable and other liabilities
                  
                  
                  (61,756
                  )
                  
                  
                  35,392
                  
                  
                  
                  (29,156
                  )Net
      cash provided by operating activities
                  
                  
                  95,235
                  
                  
                  
                  270,480
                  
                  
                  
                  124,434Cash
      flows from investing activitiesPurchases
      of property, plant and equipment
                  
                  
                  (51,169
                  )
                  
                  
                  (41,088
                  )
                  
                  
                  (32,575
                  )Other,
      net
                  
                  
                  167
                  
                  
                  
                  372
                  
                  
                  
                  (317
                  )Net
      cash used in investing activities
                  
                  
                  (51,002
                  )
                  
                  
                  (40,716
                  )
                  
                  
                  (32,892
                  )Cash
      flows from financing activitiesProceeds
      from borrowings under credit facility
                  
                  
                  185,265
                  
                  
                  
                  721,300
                  
                  
                  
                  -Repayments
      on credit facility
                  
                  
                  (323,800
                  )
                  
                  
                  (95,000
                  )
                  
                  
                  -Proceeds
      from issuance of senior notes
                  
                  
                  250,000
                  
                  
                  
                  -
                  
                  
                  
                  -Repurchases
      of senior notes
                  
                  
                  (26,832
                  )
                  
                  
                  -
                  
                  
                  
                  -Repayment
      of affiliated indebtedness
                  
                  
                  -
                  
                  
                  
                  (665,692
                  )
                  
                  
                  -Proceeds
      from equity offerings
                  
                  
                  -
                  
                  
                  
                  777,471
                  
                  
                  
                  -Distributions
      to unitholders
                  
                  
                  (90,932
                  )
                  
                  
                  (31,221
                  )
                  
                  
                  -General
      partner contributions
                  
                  
                  8
                  
                  
                  
                  -
                  
                  
                  
                  -Costs
      incurred in connection with public offerings
                  
                  
                  (89
                  )
                  
                  
                  (4,640
                  )
                  
                  
                  -Costs
      incurred in connection with financing arrangements
                  
                  
                  (7,079
                  )
                  
                  
                  (7,491
                  )
                  
                  
                  -Deemed
      Parent distributions
                  
                  
                  -
                  
                  
                  
                  (873,497
                  )
                  
                  
                  (91,542
                  )Net
      cash used in financing activities
                  
                  
                  (13,459
                  )
                  
                  
                  (178,770
                  )
                  
                  
                  (91,542
                  )Net
      change in cash and cash equivalents
                  
                  
                  30,774
                  
                  
                  
                  50,994
                  
                  
                  
                  -Cash
      and cash equivalents, beginning of year
                  
                  
                  50,994
                  
                  
                  
                  -
                  
                  
                  
                  -Cash
      and cash equivalents, end of year
                  
                  $
                  81,768
                  
                  
                  $
                  50,994
                  
                  
                  $
                  -Supplemental
      cash flow information:Net
      settlement of allocated indebtedness and debt issue costs
                  
                  $
                  -
                  
                  
                  $
                  301,801
                  
                  
                  $
                  330Net
      contribution of affiliated receivables
                  
                  
                  -
                  
                  
                  
                  184,462
                  
                  
                  
                  -Noncash
      long-term debt allocation of payments from Parent
                  
                  
                  -
                  
                  
                  
                  59,400
                  
                  
                  
                  5,979Interest
      paid
                  
                  
                  29,271
                  
                  
                  
                  15,453
                  
                  
                  
                  -Debt
      issue costs allocated from Parent
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  5,903See
      notes to consolidated financial statements


F-8
 TABLE OF CONTENTS


TARGA
RESOURCES PARTNERS LP





NOTES TO CONSOLIDATED FINANCIAL STATEMENTS





Note
1—Organization and Operations





Targa
Resources Partners LP, together with our subsidiaries (“we,” “us,” “our” or the
“Partnership”), is a publicly traded Delaware limited partnership formed on
October 26, 2006 by Targa Resources, Inc. (“Targa” or “Parent”), a leading
provider of midstream natural gas and NGL services in the United States, 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
natural gas liquids (“NGLs”) and NGL products. We currently operate in the Fort
Worth Basin/Bend Arch in North Texas (the “Fort Worth Basin”), the Permian Basin
of West Texas and in Southwest Louisiana.





Initial
Public Offering





On
February 14, 2007, we completed our initial public offering (“IPO”) of common
units representing limited partner interests in the Partnership. In the IPO, we
issued 19,320,000 common units at a price of $21.00 per unit. We used the net
proceeds of the IPO (including 2,520,000 common units sold pursuant to the full
exercise by the underwriters of their option to purchase additional common
units) to pay expenses related to the IPO and our new senior secured revolving
credit facility (“credit facility”) and to repay approximately $371.2 million of
our outstanding allocated indebtedness. Concurrent with the IPO, Targa
contributed its interest in Targa North Texas GP LLC and Targa North Texas LP
(collectively the “North Texas System”) to us. Targa indirectly received a 2%
general partnership interest in us (629,555 general partner units), incentive
distribution rights, and a limited partnership interest in us (represented by
11,528,231 subordinated units). Our common units are listed on The NASDAQ Stock
Market LLC under the symbol “NGLS.”





Acquisition
of SAOU and LOU Systems





On
October 24, 2007, we completed the purchase from Targa of its ownership
interests in Targa Texas Field Services LP, (the “SAOU System”), and Targa
Louisiana Field Services LLC (the “LOU System”). This acquisition consisted of
the SAOU System’s natural gas gathering and processing businesses located in the
Permian Basin of West Texas and the LOU System’s natural gas gathering and
processing businesses located in Southwest Louisiana. The total value of the
transaction was approximately $706 million. In addition, we paid approximately
$24.2 million to Targa for the termination of certain hedge transactions.
Concurrent with the acquisition, we sold 13,500,000 common units representing
limited partnership interests in us at a price of $26.87 per common unit
($25.796 per common unit after the underwriting discount). Total consideration
paid by us to Targa consisted of cash of approximately $722.5 million and
312,246 general partner units issued to Targa to allow it to maintain its 2%
general partner interest in us. On November 20, 2007, the underwriters exercised
their option to purchase an additional 1,800,000 common units at the same $26.87
price per common unit. The net proceeds from the underwriters’ exercise were
used to reduce borrowings under our credit facility by approximately $47
million.





Note
2—Basis of Presentation





The
consolidated financial statements include our accounts and: (i) prior to October
24, 2007 the assets, liabilities and operations of the SAOU and LOU Systems; and
(ii) prior to February 14, 2007 the assets, liabilities and operations of the
North Texas System.







Targa’s conveyance to us
of the North Texas System and our acquisition from Targa of the SAOU and LOU
Systems has 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 basis in the net assets. 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
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 partners’ equity.





F-9
 TABLE OF CONTENTS


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 System and the LOU System, 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 an
unaffiliated entity. All significant intercompany balances and transactions have
been eliminated. Certain reclassifications have been made to the previous years
to conform to the 2008 presentation. Transactions between us and other Targa
operations have been identified in the consolidated financial statements as
transactions between affiliates.





We have
been allocated general and administrative expenses incurred by the Parent in
order to present financial statements on a stand-alone basis. See Note 10. 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.





Note
3—SignificantAccounting 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 a systematic and rational
allocation 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. 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.




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.





Comprehensive
Income.Comprehensive income includes net income and other comprehensive
income, which includes unrealized gains and losses on derivative instruments
that are designated as hedges.





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. We do not have an allowance for doubtful
accounts as of December 31, 2008, and we have not recognized any bad debt
expense for the three-year period then ended.





Commodity Derivative Instruments.As of December 31, 2008, affiliates of Goldman Sachs, Merrill Lynch and
Barclays Bank accounted for 67%, 21% and 11% of our counterparty credit exposure
related to commodity derivative instruments. Goldman Sachs, Merrill Lynch and
Barclays Bank are major financial institutions, each possessing investment grade
credit ratings, based upon minimum credit ratings assigned by Standard &
Poor’s Ratings Services, a division of the McGraw-Hill Companies,
Inc.





Debt
Issue Costs.Costs incurred in connection with the issuance of long-term
debt are capitalized and charged to interest expense over the term of the
related debt.


F-10
 TABLE OF CONTENTS





Environmental
Liabilities.Liabilities for loss contingencies, including environmental
remediation costs arising from claims, assessments, litigation, fines, and
penalties and other sources are charged to expense when it is probable that a
liability has been incurred and the amount of the assessment and/or remediation
can be reasonably estimated.





Income
Taxes.We are not subject to federal income taxes. As a result, our
earnings or losses for federal income tax purposes are included in the tax
returns of our individual partners. 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 presently recorded as a deferred tax
liability.





We have
determined that there are no significant uncertain tax positions requiring
recognition in our financial statements as of December 31, 2008. There are no
unrecognized tax benefits that, if recognized, would affect the effective rate,
and there are no unrecognized tax benefits that are reasonably expected to
increase or decrease in the next twelve months. We file tax returns in the
United States Federal and several state jurisdictions, and are open to federal
and state income tax examinations for years 2007 forward. Presently, no income
tax examinations are underway, and none have been announced. No potential
interest or penalties were recognized as of December 31, 2008.





Inventory
Imbalance.Quantities of natural gas and/or NGLs over-delivered or
under-delivered related to 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 typically settled in the following month
with deliveries of natural gas or NGLs. Certain contracts require cash
settlement of imbalances on a current basis. Under these contracts, imbalance
cash-outs are recorded as a sale or purchase of natural gas, as
appropriate.





Net
Income per Limited Partner Unit.We compute earnings per
unit using the Two-Class Method.The Two-Class
Methodrequires 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 Methoddoes 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.





Our net
income is allocated to the general partner and the limited partners, including
the holders of the subordinated units, 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, less general
partner incentive distributions, by the applicable weighted average number of
outstanding limited partner units during the period.





The
calculation of net income per limited and subordinated partner unit for 2006 is
not presented as we did not have any outstanding units until we completed our
IPO on February 14, 2007. The calculation of basic and diluted net income per
common and subordinated unit are the same for all periods presented as
distributable cash flow was greater than net income for those periods and
distributions to the subordinated unitholders have been equivalent to the
distribution to the common unitholders for all quarters.





F-11
 TABLE OF CONTENTS


Price
Risk Management (Hedging).All derivative
instruments not qualifying for the normal purchases and normal sales exception
are recorded on the balance sheet 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
other comprehensive income (“OCI”), a component of partners’ capital, 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.





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
      ofYearsGas
      gathering systems and processing systems
                    
                    15
      to 25Other
      property and equipment
                    
                    3
      to 7








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.




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. From time to time, we utilize
consultants and other experts to assist us in assessing the remaining lives of
the crude oil or natural gas production in the basins we serve.




We may
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 amount of the assets. We
continually monitor our businesses and the market and business environments to
identify indicators that may suggest an asset may not be
recoverable.




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 TABLE OF CONTENTS


We
evaluate an asset for recoverability by comparing the carrying value of the
asset with the asset’s expected future undiscounted cash flows. These cash flow
estimates require us to make projections and assumptions for many years into the
future for pricing, demand, competition, operating cost and other factors. If
the carrying amount exceeds the expected future undiscounted cash flows we
recognize an impairment loss to write down the carrying amount of the asset to
its fair value as determined by quoted market prices in active markets or
present value techniques if quotes are unavailable. The determination of the
fair value using present value techniques requires us to make projections and
assumptions regarding the probability of a range of outcomes and the rates of
interest used in the present value calculations. Any changes we make to these
projections and assumptions could result in significant revisions to our
evaluation of recoverability of our property, plant and equipment and the
recognition of an impairment loss in our Consolidated Statements of
Operations.





Revenue
Recognition.Our primary types
of sales and service activities reported as operating revenues
include:





·
            sales
      of natural gas, NGLs and condensate;
and


·
            natural
      gas processing, from which we generate revenues through the compression,
      gathering, treating, and processing of natural
  gas.





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.





Segment
Information.We operate in one
segment only, the natural gas gathering and processing segment.





Unit-Based
Employee Compensation.We award share-based compensation to directors in
the form of restricted common units. 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 8.





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 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.





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 TABLE OF CONTENTS


Accounting
Pronouncements Recently Adopted





In September 2006, the
Financial Accounting Standards Board (“FASB”) issued Statement of Financial
Accounting Standards (“SFAS”) 157,“Fair
Value Measurements.”SFAS 157 establishes a
framework for measuring fair value and expands disclosures about fair value
measurements.In February 2008, the FASB issued FASB Staff Position
FAS 157-2, “Effective Date of
FASB Statement No. 157,”which delayed the effective date of SFAS
157 for all non-financial assets and liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis, until January 1, 2009.





We have not yet
conclusively determined the impact thatourimplementation of SFAS
157 will have on our non-financial assets and liabilities; however we do not
anticipate it to significantly impact our consolidated financial
statements.We adopted
SFAS 157 with respect to financial assets and liabilities that are recognized on
a recurring basis on January 1, 2008. Although the adoption of SFAS 157 did not
materially impact our financial condition, results of operations, or cash flows,
we are now required to provide additional disclosures as part of our financial
statements. See Note 13.





In March
2008, the FASB issued SFAS 161, “Disclosures
about Derivative Instruments and Hedging Activities — an amendment of FASB
Statement No. 133.”SFAS 161 changes the disclosure requirements for
derivative instruments and hedging activities. Entities are required to provide
enhanced disclosures about (a) how and why an entity uses derivative
instruments, (b) how derivative instruments and related hedged items are
accounted for under SFAS 133, “Derivative
Instruments and Hedging Activities” and its related interpretations, and
(c) how derivative instruments and related hedged items affect an entity’s
financial position, financial performance, and cash flows. SFAS 161 is effective
for financial statements issued for fiscal years and interim periods beginning
after November 15, 2008. Early adoption is encouraged. Our adoption of SFAS 161
as of December 31, 2008 did not impact our consolidated financial position,
results of operations or cash flows. See Note 10.





Accounting
Pronouncements Recently Issued




In
December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combination.”
(“SFAS 141R”). SFAS 141R establishes principles and requirements for
how an acquirer recognizes and measures in its financial statements the
identifiable assets acquired, the liabilities assumed, any noncontrolling
interest in the acquiree and the goodwill acquired. SFAS 141R also
establishes disclosure requirements to enable the evaluation of the nature and
financial effects of the business combination. SFAS 141R is effective as of
the beginning of an entity’s fiscal year that begins after December 15,
2008. This new accounting standard will only impact how we account for business
combinations on a prospective basis.





In March
2008, the FASB’s Emerging Issues Task Force (“EITF”) reached a consensus on EITF
07-4, “Application
of the Two - Class Method under FASB Statement No. 128, Earnings per Share, to
Master Limited Partnerships.”EITF 07-4 improves the comparability of
earnings per unit calculations for master limited partnerships (“MLPs”) with
incentive distribution rights (“IDRs”) in accordance with Statement 128 and its
related interpretations. Under EITF 07-4, when an MLP’s current-period earnings
are in excess of cash distributions and the IDRs are a separate limited partner
interest, undistributed earnings should be allocated to the general partner,
limited partners and IDR holder utilizing the contractual terms of the
partnership agreement. The distribution formula for available cash specified in
the partnership agreement contractually mandates the way in which earnings are
distributed.





Additionally,
EITF 07-4 requires an MLP to reflect its contractual obligation to make
distributions as of the end of the current reporting period. Therefore, an MLP
would reduce (increase) income (loss) from continuing operations (or net income
or loss) for the current reporting period by the amount of available cash that
has been or will be distributed to the general partner, limited partners, and
IDR holder for that current reporting period. If distributions to the IDR holder
are contractually limited to available cash as defined in the partnership
agreement, then the specified threshold for the current reporting period would
be the holder’s share of available cash that has been or will be distributed to
the IDR holder for that current reporting period.





EITF 07-4
is effective for financial statements issued for fiscal years beginning after
December 15, 2008, and interim periods within those fiscal years. Earlier
application is not permitted. Our adoption of EITF 07-4 is not expected to
impact our consolidated financial position, results of operations, cash flows or
our computation of earnings per common and subordinated unit.


F-14
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Note
4—Property, Plant and Equipment





Property,
plant, and equipment and accumulated depreciation were as follows as of the
dates indicated:





December 31,2008
                  
                  
                  2007(In
      thousands)Natural
      Gas Gathering Systems
                  
                  $
                  1,161,942
                  
                  
                  $
                  1,132,860Processing
      and fractionation facilities
                  
                  
                  237,321
                  
                  
                  
                  230,931Other
      property, plant, and equipment
                  
                  
                  68,003
                  
                  
                  
                  60,946Construction
      in progress
                  
                  
                  25,460
                  
                  
                  
                  9,2181,492,726
                  
                  
                  
                  1,433,955Accumulated
      depreciation
                  
                  
                  (248,389
                  )
                  
                  
                  (174,361
                  )$
                  1,244,337
                  
                  
                  $
                  1,259,594








Note
5—Asset Retirement Obligations





The
changes in our aggregate asset retirement obligations are as
follows:





Year Ended December 31,2008
                  
                  
                  2007
                  
                  
                  2006(In
      thousands)Beginning
      of year
                  
                  $
                  3,262
                  
                  
                  $
                  2,888
                  
                  
                  $
                  2,644Liabilities
      settled
                  
                  
                  (229
                  )
                  
                  
                  -
                  
                  
                  
                  -Change
      in cash flow estimate
                  
                  
                  258
                  
                  
                  
                  32
                  
                  
                  
                  (1
                  )Accretion
      expense
                  
                  
                  231
                  
                  
                  
                  342
                  
                  
                  
                  245End
      of period
                  
                  $
                  3,522
                  
                  
                  $
                  3,262
                  
                  
                  $
                  2,888





Our asset
retirement obligations are included in our Consolidated Balance Sheets as a
component of other long-term liabilities.





Note
6—Debt Obligations





Our
consolidated outstanding debt, including outstanding borrowings and issued
letters of credit as of the dates shown below was:








December
      31,2008
                      
                      
                      2007(In
      thousands)Senior
      unsecured notes, 81⁄4% fixed rate, due July 1, 2016
                      
                      $
                      209,080
                      
                      
                      $
                      -Senior
      secured credit facility, variable rate, due February 14,
    2012
                      
                      
                      487,765
                      
                      
                      
                      626,300Total
      long-term debt
                      
                      $
                      696,845
                      
                      
                      $
                      626,300Letters
      of credit issued
                      
                      $
                      9,651
                      
                      
                      $
                      25,900





On
October 16, 2008, we requested a $100 million funding under our credit facility.
Lehman Bank, a lender under our credit facility, defaulted on its portion of the
borrowing request resulting in an actual funding of $97.8 million. As a result
of the default, we believe the availability under the credit facility has been
effectively reduced by approximately $10.0 million.





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 TABLE OF CONTENTS


Repurchases
of Senior Notes





During
November and December 2008, we repurchased $40.9 million face amount of our
outstanding Senior 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 of $13.1 million from these transactions. The repurchased Notes were
retired and are not eligible for re-issue at a later date.





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
2008:





Range
      of interest
                  rates paid
                
                Weighted
      average
                  interest rate paidCredit
      facility
                1.5%
      to 6.4%
                
                
                4.4
                %





Pre-IPO
Indebtedness





On
January 1, 2007, Targa contributed to us affiliated indebtedness related to the
North Texas System of approximately $904.5 million (including accrued interest
of $88.3 million computed at 10% per annum). We recorded approximately $9.8
million in interest expense associated with this affiliated debt for the period
from January 1, 2007 through February 13, 2007. On February 14, 2007, Targa
contributed its interest in Targa North Texas GP LLC and Targa North Texas LP to
us.





The
stated 10% interest rate in the formal debt arrangement was not indicative of
prevailing external rates of interest including that incurred under our credit
facility which is secured by substantially all of our assets. On a pro forma
basis, at prevailing interest rates the affiliated interest expense for the
period from January 1, 2007 to February 13, 2007 would have been reduced by $3.0
million. The pro forma interest expense adjustment has been calculated by
applying the weighted average rate of 6.9% that we incurred under our credit
facility to the affiliate debt balance for the period from January 1, 2007 to
February 13, 2007.





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. 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. We initially borrowed $342.5 million under our credit facility,
and concurrently repaid $48.0 million under our credit facility with the
proceeds from the 2,520,000 common units sold pursuant to the full exercise by
the underwriters of their option to purchase additional common units. The net
proceeds of $294.5 million from this borrowing, together with approximately
$371.2 million of available cash from the IPO (after payment of offering and
debt issue costs and necessary operating cash reserve balances), were used to
repay approximately $665.7 million of affiliate indebtedness. In connection with
our IPO, the guarantee of indebtedness from the entity holding the North Texas
System was terminated, the related collateral interest was released and the
remaining affiliate indebtedness was retired and treated as a capital
contribution to us. Our credit facility is secured by substantially all of our
assets.





On
October 24, 2007, we completed the acquisition of the SAOU and LOU Systems from
Targa. As part of the acquisition of the SAOU and LOU Systems, the allocated
indebtedness was settled with Targa through an adjustment to parent equity and
the collateralization of the assets was released.





Concurrent
with the acquisition of the SAOU and LOU Systems, we entered into a Commitment
Increase Supplement (the “Supplement”) to our existing credit facility. The
Supplement increased the aggregate commitments under the Credit Agreement by
$250 million to an aggregate $750 million. We paid for our acquisition of the
SAOU and LOU Systems with the proceeds from our offering of common units and
approximately $378.9 million in incremental borrowings under the increased
credit facility. Substantially all of our assets (North Texas, SAOU and LOU
Systems) are currently pledged as collateral on our credit
facility.


F-16
 TABLE OF CONTENTS


On
October 24, 2007, we entered into the First Amendment to Credit Agreement (the
“Amendment”). The Amendment increased by $250 million the maximum amount of
increases to the aggregate commitments that may be requested by us. The
Amendment allows us to request commitments under the credit agreement, as
supplemented and amended, up to $1 billion.





On June
18, 2008, we increased the commitments under our credit facility by $100
million, bringing the total commitments under our credit facility to $850
million. We may request additional commitments under our credit facility of up
to $150 million, which would increase the total commitments under our credit
facility to $1 billion.





The
credit agreement restricts our ability to make distributions of available cash
to unitholders if we are in any default or an event of default (as defined in
the credit agreement) exists. The credit agreement requires us to maintain a
leverage ratio (the ratio of consolidated indebtedness to our consolidated
EBITDA, as defined in the credit agreement) of no more than 5.50 to 1.00 on the
last day of any fiscal quarter. The credit agreement also requires us to
maintain an interest coverage ratio (the ratio of our consolidated EBITDA to our
consolidated interest expense, as defined in the credit agreement) of no less
than 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. In addition, the
credit agreement contains various covenants that may limit, among other things,
our ability to:





·
            incur
      indebtedness;





·
            grant
      liens; and





·
            engage
      in transactions with affiliates.





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 (“Rule 144A”) of $250 million in aggregate principal
amount of 81⁄4%
senior notes due 2016 (the “Notes”). Proceeds from the Notes were used to repay
borrowings under our credit facility.





The
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





·
            are
      unconditionally guaranteed by us.





The 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 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. Interest is computed on the basis of a 360-day year comprising twelve
30-day months.





At any
time prior to July 1, 2011, we may on any one or more occasions redeem up to 35%
of the aggregate principal amount of the 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 Notes (excluding 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.


F-17
 TABLE OF CONTENTS





At any
time prior to July 1, 2012, we may also redeem all or a part of the Notes at a
redemption price equal to 100% of the principal amount of the 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 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 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
                  %








The Notes
are subject to a registration rights agreement dated as of June 18, 2008. Under
the registration rights agreement, we are required to file by June 19, 2009 a
registration statement with respect to any Notes that are not freely
transferable without volume restrictions by holders of the Notes that are not
our affiliates. If we fail to do so, additional interest will accrue on the
principal amount of the 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 accrual of a liability under this
registration rights agreement will be charged to earnings as interest
expense.








Note
7—Partnership Equity and Distributions





General.The partnership agreement requires that, within 45 days after the end of
each quarter, we distribute all of our Available Cash (defined below) to
unitholders of record on the applicable record date, as determined by the
general partner.





Definition
of Available Cash.Available Cash, for any quarter, consists of 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 the general
partner to:





·
            provide
      for the proper conduct of our
business;





·
            comply
      with applicable law, any of our debt instruments or other agreements;
      or





·
            provide
      funds for distributions to the unitholders and to the general partner for
      any one or more of the next four
quarters.





General
Partner Interest and Incentive Distribution Rights.The general partner
is currently entitled to approximately 2% of all quarterly distributions that we
make prior to our liquidation. The general partner has the right, but not the
obligation, to contribute a proportionate 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 the
general partner does not contribute a proportionate amount of capital to us to
maintain its 2% general partner interest.





The
incentive distribution rights held by the general partner entitle it to receive
an increasing share of Available Cash when pre-defined distribution targets are
achieved. The general partner’s incentive distribution rights are not reduced if
we issue additional units in the future and the general partner does not
contribute a proportionate amount of capital to us to maintain its 2% general
partner interest. Please read “Distributions of Available Cash during the
Subordination Period” and “Distributions of Available Cash after the
Subordination Period” below for more details about the distribution targets and
their impact on the general partner’s incentive distribution
rights.





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 TABLE OF CONTENTS


Subordinated
Units.All of the subordinated units are indirectly held by Targa. Our
partnership agreement provides that, during the subordination period, the common
units have the right to receive distributions of Available Cash each quarter in
an amount equal to $0.3375 per common unit, or the “Minimum Quarterly
Distribution,” plus any arrearages in the payment of the Minimum Quarterly
Distribution on the common units from prior quarters, before any distributions
of Available Cash may be made on the subordinated units. These units are deemed
“subordinated” because for a period of time, referred to as the subordination
period, the subordinated units will not be entitled to receive any distributions
until the common units have received the Minimum Quarterly Distribution plus any
arrearages from prior quarters. Furthermore, no arrearages will be paid on the
subordinated units. The practical effect of the subordinated units is to
increase the likelihood that during the subordination period there will be
Available Cash to be distributed on the common units. The subordination period
will end, and the subordinated units will convert to common units, on a one for
one basis, when certain distribution requirements, as defined in the partnership
agreement, have been met. The earliest date at which the subordination period
may end is May 19, 2009.





Distributions
of Available Cash during the Subordination Period.Based on the general
partner’s initial 2% ownership percentage, the partnership agreement requires
that we make distributions of Available Cash from operating surplus for any
quarter during the subordination period in the following manner:





·
            first,
      98% to the common unitholders, pro rata, and 2% to the general partner,
      until we distribute for each outstanding common unit an amount equal to
      the Minimum Quarterly Distribution for that quarter;





·
            second,
      98% to the common unitholders, pro rata, and 2% to the general partner,
      until we distribute for each outstanding common unit an amount equal to
      any arrearages in payment of the Minimum Quarterly Distribution on the
      common units for any prior quarters during the subordination period;





·
            third,
      98% to the subordinated unitholders, pro rata, and 2% to the general
      partner, until we distribute for each subordinated unit an amount equal to
      the Minimum Quarterly Distribution for that quarter;





·
            fourth,
      98% to all unitholders, pro rata, and 2% to the general partner, until
      each unitholder receives a total of $0.3881 per unit for that quarter (the
      First Target Distribution);





·
            fifth,
      85% to all unitholders, 2% to the general partner and 13% to the holders
      of the Incentive Distribution Rights, pro rata, until each unitholder
      receives a total of $0.4219 per unit for that quarter (the Second Target
      Distribution);





·
            sixth,
      75% to all unitholders, 2% to the general partner and 23% to the holders
      of the Incentive Distribution Rights, pro rata, until each unitholder
      receives a total of $0.50625 per unit for that quarter (the Third Target
      Distribution); and





·
            thereafter,
      50% to all unitholders, 2% to the general partner and 48% to the holders
      of the Incentive Distribution Rights, pro rata, (the Fourth Target
      Distribution).





Distributions
of Available Cash after the Subordination Period.The partnership
agreement requires that we make distributions of Available Cash from operating
surplus for any quarter after the subordination period in the following
manner:





·
            first,
      98% to all unitholders, pro rata, and 2% to the general partner, until
      each unitholder receives a total of $0.3881 per unit for that quarter;





·
            second,
      85% to all unitholders, pro rata, 2% to the general partner and 13% to the
      holders of the Incentive Distribution Rights, until each unitholder
      receives a total of $0.4219 per unit for that quarter;





·
            third,
      75% to all unitholders, pro rata, 2% to the general partner and 23% to the
      holders of the Incentive Distribution Rights, until each unitholder
      receives a total of $0.50625 per unit for that quarter; and





·
            thereafter,
      50% to all unitholders, pro rata, 2% to the general partner and 48% to the
      holders of the Incentive Distribution
Rights.





F-19
 TABLE OF CONTENTS


The
following table shows the amount of the cash distributions we paid for the
period from February 14, 2007 through December 31, 2008.





Distributions Paid
                    
                    
                    DistributionsCommon
                    
                    
                    Subordinated
                    
                    
                    General Partner
                    
                    
                    
                    
                    
                    per
      limitedDate Declared
                    Date Paid
                    
                    Units
                    
                    
                    Units
                    
                    
                    Incentive
                    
                    
                    
                    2
                    %
                    
                    Total
                    
                    
                    partner unit(In
      thousands, except per unit amounts)October
      23, 2008
                    November
      14, 2008
                    
                    $
                    17,934
                    
                    
                    $
                    5,966
                    
                    
                    $
                    1,931
                    
                    
                    $
                    527
                    
                    
                    $
                    26,358
                    
                    
                    $
                    0.51750July
      23, 2008
                    August
      14, 2008
                    
                    
                    17,759
                    
                    
                    
                    5,908
                    
                    
                    
                    1,711
                    
                    
                    
                    518
                    
                    
                    
                    25,896
                    
                    
                    
                    0.51250April
      23, 2008
                    May
      15, 2008
                    
                    
                    14,467
                    
                    
                    
                    4,813
                    
                    
                    
                    208
                    
                    
                    
                    398
                    
                    
                    
                    19,886
                    
                    
                    
                    0.41750January
      23, 2008
                    February
      14, 2008
                    
                    
                    13,768
                    
                    
                    
                    4,582
                    
                    
                    
                    66
                    
                    
                    
                    376
                    
                    
                    
                    18,792
                    
                    
                    
                    0.39750July
      24, 2007
                    November
      14, 2007
                    
                    
                    11,082
                    
                    
                    
                    3,891
                    
                    
                    
                    -
                    
                    
                    
                    305
                    
                    
                    
                    15,278
                    
                    
                    
                    0.33750July
      24, 2007
                    August
      14, 2007
                    
                    
                    6,526
                    
                    
                    
                    3,890
                    
                    
                    
                    -
                    
                    
                    
                    212
                    
                    
                    
                    10,628
                    
                    
                    
                    0.33750April
      23, 2007
                    May
      15, 2007
                    
                    
                    3,263
                    
                    
                    
                    1,945
                    
                    
                    
                    -
                    
                    
                    
                    107
                    
                    
                    
                    5,315
                    
                    
                    
                    0.16875





On
January 23, 2009, we declared a cash distribution of $0.5175 per unit on
our outstanding common and subordinated units. The distribution was paid on
February 13, 2009 to unitholders of record on February 4, 2008, for
the period October 1, 2008 through December 31, 2008. The total
distribution paid was approximately $26.4 million, with approximately
$23.9 million paid to our common unitholders and $0.5 million and
$1.9 million paid to our general partner for its general partner and
incentive distribution interests.








Note
8—Accounting for Unit-Based Compensation





Our
general partner has adopted a long-term incentive plan (“the Plan”) for
employees, consultants and directors of the general partner and its affiliates
who perform services for us. The following table
summarizes our unit-based awards for each of the periods
indicated:








Year Ended December 31,2008
                
                
                2007
                
                
                2006Outstanding
      at beginning of period
                
                
                16,000
                
                
                
                -
                
                
                
                -Granted
                
                
                16,000
                
                
                
                16,000
                
                
                
                -Vested
                
                
                (5,336
                )
                
                
                -
                
                
                
                -Forfeited
                
                
                -
                
                
                
                -
                
                
                
                -Outstanding
      at end of period
                
                
                26,664
                
                
                
                16,000
                
                
                
                -Weighted
      average grant date fair value per share
                
                $
                22.12
                
                
                $
                21.00
                
                
                $
                -





During
2008 and 2007, our general partner awarded 2,000 restricted common units in the
Partnership to each of the general partner’s and Targa Investments’
non-management directors under the 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.





Compensation
expense on the restricted common units is recognized on a straight-line basis
over the vesting period. The fair value of an award of restricted common units
is measured on the grant date using the market price of a common unit on such
date. During 2008 and 2007, we recognized compensation expense of $0.3 million
and $0.2 million related to these awards. We estimate that the remaining fair
value of $0.2 million will be recognized in expense over approximately one
year.








Note
9 — Derivative Instruments and Hedging
Activities





As of
December 31, 2008, OCI included $89.6 million of unrealized net gains on
commodity hedges. As of December 31, 2007, OCI included $74.0 million of
unrealized net losses on commodity hedges.





For
2008, 2007 and 2006 deferred net losses on commodity hedges of $33.7million, $1.0
million and $0.9 million were reclassified from OCI to revenues. There were no
adjustments for hedge ineffectiveness for 2008, 2007 or 2006.


F-20
 TABLE OF CONTENTS





As of
December 31, 2008 and 2007, OCI also included $17.6 million and$1.2 million of unrealized losses on interest rate hedges.





For 2008,
2007 and 2006, deferred net gain (losses) on interest rate hedges of $2.7million,
($0.2) million and ($0.5) million were reclassified from OCI to net interest
expense. There were no adjustments for hedge ineffectiveness for 2008, 2007 or
2006.





As of
December 31, 2008, deferred net gains (losses) of $50.0million on
commodity hedges and ($8.0) 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 as of July 1, 2008.
Deferred losses of $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. On October 22, 2008, we terminated the
Lehman derivative contracts.





During
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 in accordance with SFAS 133. Deferred losses will be
reclassified from OCI as a non-cash reduction of revenue when the hedged
forecasted sales transactions occurs. During 2008, deferred losses of $20.8
million 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.





F-21
 TABLE OF CONTENTS


As of
December 31, 2008, our commodity hedges that have been designated as cash flow
hedges were as follows:





Natural
      GasAvg.
      Price
                          
                          
                          MMBtu per dayInstrument Type
                          Index
                          
                          $/MMBtu
                          
                          
                          2009
                          
                          
                          2010
                          
                          
                          2011
                          
                          
                          2012
                          
                          Fair Value(In
      thousands)Natural
      Gas SalesSwap
                          IF-HSC
                          
                          
                          7.39
                          
                          
                          
                          1,966
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          $
                          1,1591,966
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -Swap
                          IF-NGPL
      MC
                          
                          
                          9.18
                          
                          
                          
                          6,256
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          9,466Swap
                          IF-NGPL
      MC
                          
                          
                          8.86
                          
                          
                          
                          -
                          
                          
                          
                          5,685
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          5,129Swap
                          IF-NGPL
      MC
                          
                          
                          7.34
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          2,750
                          
                          
                          
                          -
                          
                          
                          
                          843Swap
                          IF-NGPL
      MC
                          
                          
                          7.18
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          2,750
                          
                          
                          
                          7386,256
                          
                          
                          
                          5,685
                          
                          
                          
                          2,750
                          
                          
                          
                          2,750Swap
                          IF-Waha
                          
                          
                          8.73
                          
                          
                          
                          6,936
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          8,627Swap
                          IF-Waha
                          
                          
                          7.52
                          
                          
                          
                          -
                          
                          
                          
                          5,709
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          2,294Swap
                          IF-Waha
                          
                          
                          7.36
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          3,250
                          
                          
                          
                          -
                          
                          
                          
                          886Swap
                          IF-Waha
                          
                          
                          7.18
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          3,250
                          
                          
                          
                          7086,936
                          
                          
                          
                          5,709
                          
                          
                          
                          3,250
                          
                          
                          
                          3,250Total
      Swaps
                          
                          
                          
                          
                          
                          
                          
                          15,158
                          
                          
                          
                          11,394
                          
                          
                          
                          6,000
                          
                          
                          
                          6,000Floor
                          IF-NGPL
      MC
                          
                          
                          6.55
                          
                          
                          
                          850
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          574850
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -Floor
                          IF-Waha
                          
                          
                          6.55
                          
                          
                          
                          565
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          326565
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -Total
      Floors
                          
                          
                          
                          
                          
                          
                          
                          1,415
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -Total
      Sales
                          
                          
                          
                          
                          
                          
                          
                          16,573
                          
                          
                          
                          11,394
                          
                          
                          
                          6,000
                          
                          
                          
                          6,000$
                          30,750NGLAvg.
      Price
                          
                          
                          Barrels per dayInstrument Type
                          Index
                          
                          $/gal
                          
                          
                          2009
                          
                          
                          2010
                          
                          
                          2011
                          
                          
                          2012
                          
                          Fair Value(In
      thousands)NGL
      SalesSwap
                          OPIS-MB
                          
                          
                          1.32
                          
                          
                          
                          6,248
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          $
                          66,137Swap
                          OPIS-MB
                          
                          
                          1.27
                          
                          
                          
                          -
                          
                          
                          
                          4,809
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          39,122Swap
                          OPIS-MB
                          
                          
                          0.92
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          3,400
                          
                          
                          
                          -
                          
                          
                          
                          8,288Swap
                          OPIS-MB
                          
                          
                          0.92
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          2,700
                          
                          
                          
                          6,018Total
      Swaps
                          
                          
                          
                          
                          
                          
                          
                          6,248
                          
                          
                          
                          4,809
                          
                          
                          
                          3,400
                          
                          
                          
                          2,700Floor
                          OPIS-MB
                          
                          
                          1.44
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          199
                          
                          
                          
                          -
                          
                          
                          
                          1,807Floor
                          OPIS-MB
                          
                          
                          1.43
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          231
                          
                          
                          
                          1,932Total
      Floors
                          
                          
                          
                          
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          199
                          
                          
                          
                          231Total
      Sales
                          
                          
                          
                          
                          
                          
                          
                          6,248
                          
                          
                          
                          4,809
                          
                          
                          
                          3,599
                          
                          
                          
                          2,931$
                          123,304


F-22
 TABLE OF CONTENTS





CondensateAvg.
      Price
                    
                    
                    Barrels per dayInstrument Type
                    Index
                    
                    $/Bbl
                    
                    
                    2009
                    
                    
                    2010
                    
                    
                    2011
                    
                    
                    2012
                    
                    Fair Value(In
      thousands)Condensate
      SalesSwap
                    NY-WTI
                    
                    
                    69.00
                    
                    
                    
                    322
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    $
                    1,655Swap
                    NY-WTI
                    
                    
                    68.10
                    
                    
                    
                    -
                    
                    
                    
                    301
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    431Total
      Swaps
                    
                    
                    
                    
                    
                    
                    
                    322
                    
                    
                    
                    301
                    
                    
                    
                    -
                    
                    
                    
                    -Floor
                    NY-WTI
                    
                    
                    60.00
                    
                    
                    
                    50
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    239Total
      Floors
                    
                    
                    
                    
                    
                    
                    
                    50
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -Total
      Sales
                    
                    
                    
                    
                    
                    
                    
                    372
                    
                    
                    
                    301
                    
                    
                    
                    -
                    
                    
                    
                    -$
                    2,325





As of
December 31, 2008, we had the following commodity derivative contracts directly
related to fixed price arrangements elected by certain customers in various
natural gas purchase and sale agreements, which have been marked to market
through earnings:





InstrumentPeriod
                  Commodity
                  Type
                  
                  Daily Volume
                  
                  Average Price
                  Index
                  
                  Fair Value(In
      thousands)PurchasesJan
      2009 - Dec 2009
                  Natural
      gas
                  Swap
                  
                  
                  6,005
                  
                  MMBtu
                  
                  
                  7.50
                  
                  per
      MMBtu
                  NY-HH
                  
                  $
                  (3,644
                  )Jan
      2010 - Jun 2010
                  Natural
      gas
                  Swap
                  
                  
                  1,304
                  
                  MMBtu
                  
                  
                  8.03
                  
                  per
      MMBtu
                  NY-HH
                  
                  
                  (113
                  )SalesJan
      2009 - Dec 2009
                  Natural
      gas
                  Fixed
      price sale
                  
                  
                  6,005
                  
                  MMBtu
                  
                  
                  7.50
                  
                  per
      MMBtu
                  NY-HH
                  
                  
                  3,610Jan
      2010 - Jun 2010
                  Natural
      gas
                  Fixed
      price sale
                  
                  
                  1,304
                  
                  MMBtu
                  
                  
                  8.03
                  
                  per
      MMBtu
                  NY-HH
                  
                  
                  113$
                  (34
                  )





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
earnings are also affected by 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 sheet 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 2008, 2007 and 2006, we recorded
mark-to-market gains (losses) of ($1.0)million,
($30.2) million and $16.8 million.





Interest
Rate Swaps





As of
December 31, 2008, we had $487.8 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:





Notional
                  AmountExpiration Date
                
                Fixed Rate
                
                Amount
                
                Fair Value(In
      thousands)January
      24, 2011
                
                
                4.00
                %
                $100
      million
                
                $
                (5,282
                )January
      24, 2012
                
                
                3.75
                %
                200
      million
                
                
                (12,294
                )$
                (17,576
                )





F-23
 TABLE OF CONTENTS





All
interest rate swaps and interest rate basis swaps have been designated as cash
flow hedges of variable rate interest payments on $50 million in borrowings
under our credit facility.





The
following schedules reflect the fair values of derivative instruments in our
Consolidated Balance Sheets and the effect of derivative instruments on our
Consolidated Statements of Operations.





Asset Derivatives
                  
                  Liability DerivativesBalance
                  
                  Fair
      Value as of
                  
                  Balance
                  
                  Fair
      Value as ofSheet
                  
                  December 31,
                  
                  Sheet
                  
                  December 31,Location
                  
                  2008
                  
                  
                  2007
                  
                  Location
                  
                  2008
                  
                  
                  2007(In
      thousands)
                  
                  
                  
                  (In
      thousands)Derivatives
      designated ashedging
      instruments underStatement
      133Commodity
      contracts
                  Current
      assets
                  
                  $
                  88,206
                  
                  
                  $
                  8,410
                  
                  Current
      liabilities
                  
                  $
                  -
                  
                  
                  $
                  43,461Other
      assets
                  
                  
                  68,296
                  
                  
                  
                  3,040
                  
                  Other
      liabilities
                  
                  
                  123
                  
                  
                  
                  42,134Interest
      rate contracts
                  Current
      assets
                  
                  
                  -
                  
                  
                  
                  -
                  
                  Current
      liabilities
                  
                  
                  8,020
                  
                  
                  
                  257Other
      assets
                  
                  
                  -
                  
                  
                  
                  -
                  
                  Other
      liabilities
                  
                  
                  9,556
                  
                  
                  
                  975Total
                  
                  
                  
                  156,502
                  
                  
                  
                  11,450
                  
                  
                  
                  
                  17,699
                  
                  
                  
                  86,827Derivatives
      not designated ashedging
      instruments underStatement
      133Commodity
      contracts
                  Current
      assets
                  
                  
                  3,610
                  
                  
                  
                  285
                  
                  Current
      liabilities
                  
                  
                  3,644
                  
                  
                  
                  285Other
      assets
                  
                  
                  -
                  
                  
                  
                  -
                  
                  Other
      liabilities
                  
                  
                  -
                  
                  
                  
                  -Total
                  
                  
                  
                  3,610
                  
                  
                  
                  285
                  
                  
                  
                  
                  3,644
                  
                  
                  
                  285Total
      derivatives
                  
                  
                  $
                  160,112
                  
                  
                  $
                  11,735
                  
                  
                  
                  $
                  21,343
                  
                  
                  $
                  87,112







Amount
      of Gain (Loss)Amount
      of Gain (Loss)
                  
                  
                  
                  Reclassified
      fromDerivatives
      in
                  
                  Recognized
      in OCI on Derivatives
                  
                  Location
      of Gain (Loss)
                  
                  Accumulated
      OCI intoStatement
      133
                  
                  (Effective
      Portion)
                  
                  Reclassified
      from
                  
                  Income
      (Effective Portion)Cash
      Flow Hedging
                  
                  Year Ended December 31,
                  
                  OCI
      into Income
                  
                  Year Ended December 31,Relationships
                  
                  2008
                  
                  
                  2007
                  
                  
                  2006
                  
                  (Effective Portion)
                  
                  2008
                  
                  
                  2007
                  
                  
                  2006(In
      thousands)
                  
                  
                  
                  (In
      thousands)Interest
      rate contracts
                  
                  $
                  (19,037
                  )
                  
                  $
                  (1,689
                  )
                  
                  $
                  1,267
                  
                  Interest
      expense, net
                  
                  $
                  (2,693
                  )
                  
                  $
                  232
                  
                  
                  $
                  -Commodity
      contracts
                  
                  
                  130,002
                  
                  
                  
                  (105,584
                  )
                  
                  
                  36,937
                  
                  Revenues
                  
                  
                  (33,650
                  )
                  
                  
                  (993
                  )
                  
                  
                  822$
                  110,965
                  
                  
                  $
                  (107,273
                  )
                  
                  $
                  38,204
                  
                  
                  
                  $
                  (36,343
                  )
                  
                  $
                  (761
                  )
                  
                  $
                  822







Derivatives
      Not
                                                    
                                                    
                                                    Amount
      of Gain (Loss) RecognizedDesignated
      as Hedging
                                                    Location
      of Gain (Loss)
                                                    
                                                    in
      Income on DerivativesInstruments
      Under
                                                    Recognized
      in Income
                                                    
                                                    Year Ended December 31,Statement 133
                                                    on Derivatives
                                                    
                                                    2008
                                                    
                                                    
                                                    2007
                                                    
                                                    
                                                    2006(In
      thousands)Commodity
      contracts
                                                    Other
      income (expense)
                                                    
                                                    $
                                                    (991
                                                    )
                                                    
                                                    $
                                                    (30,221
                                                    )
                                                    
                                                    $
                                                    16,756





See also
Note 3 and Note 12 for additional disclosures related to derivative instruments
and hedging activities.





F-24
 TABLE OF CONTENTS





Note
10—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 11, 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.





Concurrently
with the closing of the acquisition of the SAOU and LOU Systems, 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. Any or
all of the provisions of the Omnibus Agreement, other than the indemnification
provisions described in Note 11, 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.





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 are capped at $5 million annually for
      three years, subject to increases based on increases in the Consumer Price
      Index and subject to further increases in connection with expansions of
      our operations through the acquisition or construction of new assets or
      businesses with the concurrence of our conflicts committee; thereafter,
      our general partner will determine the general and administrative expenses
      to be allocated to us in accordance with our partnership agreement,
      and





·
            operations
      and certain direct general and administrative expenses, which are not
      subject to the $5 million cap for general and administrative
      expenses.





With
respect to the SAOU and LOU Systems, we will reimburse Targa for the following
expenses:





·
            general
      and administrative expenses, which are not capped, allocated to the SAOU
      and LOU Systems according to Targa’s allocation practice;
    and





·
            operating
      and certain direct expenses, which are not
  capped.





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.





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 NGLs.
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 inter-company transactions was through adjustments to partners’ capital
accounts. Effective February 14, 2007, all of the North Texas Systems
transactions were settled monthly in cash. Effective October 23, 2007, all of
the SAOU and LOU Systems’ transactions were settled in cash.





F-25
 TABLE OF CONTENTS


NGL
and Condensate Purchase Agreement for the North Texas System.During
2007, we entered into an NGL and high pressure condensate purchase agreement
with Targa Liquids Marketing and Trade (“TLMT”) for our North Texas System,
which has an initial term of 15 years and will automatically extend for a term
of five years, unless the agreement is otherwise terminated by either party,
pursuant to which (i) we are obligated to sell all volumes of NGLs (other than
high-pressure condensate) that we own or control to TLMT and (ii) we have the
right to sell to TLMT or third parties the volumes of high-pressure condensate
that we own or control, in each case at a price based on the prevailing market
price less transportation, fractionation and certain other fees. Furthermore,
either party may elect to terminate the agreement if either party ceases to be
an affiliate of Targa.





NGL
Purchase Agreements for the SAOU and LOU Systems.During 2007, the SAOU
System entered into an NGL purchase agreement pursuant to which it is obligated
to sell all volumes of mixed NGLs, or raw product, that it owns or controls to
TLMT at a price based on either TLMT’s sales price to third parties or the
prevailing market price, less transportation, fractionation and certain other
fees. The LOU System also has entered into an NGL purchase agreement pursuant to
which (i) it has the right to sell to TLMT the volumes of raw product that it
owns or controls at a commercially reasonable price agreed by the parties, and
(ii) it is obligated to sell all volumes of fractionated NGL components that it
owns or controls at a price based on TLMT’s sales price to third parties or the
prevailing market price, less transportation, fractionation and certain other
fees. Both NGL purchase agreements have an initial term of one year and
automatically extend for additional terms of one year, unless the agreements are
otherwise terminated by either party.





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.





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 Systems
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 were
based on the fair 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, were settled through a deemed partner contribution
of $846.3 million on January 1, 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.





F-26
 TABLE OF CONTENTS


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 by Targa and the acquisition of the
SAOU/LOU Systems from Targa. Management believes these transactions are executed
on terms that are fair and reasonable.





Year Ended December 31,2008
                
                
                2007
                
                
                2006(In
      thousands)Sales
      to affiliates
                
                $
                1,225,393
                
                
                $
                1,030,696
                
                
                $
                786,589Purchases
      from affiliates
                
                
                323,970
                
                
                
                191,064
                
                
                
                322,917Allocations
      of general & administrative expenses - pre IPO
                
                
                -
                
                
                
                9,720
                
                
                
                16,062Allocations
      of general & administrative expenses under Omnibus
      Agreement
                
                
                18,204
                
                
                
                5,927
                
                
                
                -Allocated
      interest
                
                
                -
                
                
                
                19,436
                
                
                
                88,025Receipts
      made by Parent on our behalf
                
                
                -
                
                
                
                584,561
                
                
                
                268,043Net
      change in affliate receivable
                
                
                (65,252
                )
                
                
                87,547
                
                
                
                -








Centralized
Cash Management





Prior to
the contribution of the assets of the North Texas, SAOU and LOU Systems 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.





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 though October 23,
2007, deemed net capital distributions from us were $133.6 million.







Relationships
with Warburg Pincus




Chansoo
Joung and Peter Kagan, two of the directors of Targa, are Managing Directors of
Warburg Pincus and are also directors of Broad Oak Energy, Inc. (“Broad Oak”)
from whom we buy natural gas and NGL products. Affiliates of Warburg Pincus own
a controlling interest in Broad Oak. We purchased $4.8 million of product from
Broad Oak during 2008. We had no commercial transactions prior to 2008 with
Broad Oak. These transactions were at market prices consistent with similar
transactions with nonaffiliated entities.




Relationships
with Noble Energy




Chris
Tong, one of the directors of Targa, is a Senior Vice President and Chief
Financial Officer of Noble Energy, Inc. (“Noble”) from whom we buy certain
commodity products. We had net purchases of less than $0.1 million, $0.1 million
and $1.7 million of natural gas and NGL products from Noble during 2008, 2007
and 2006.  These transactions were at market prices consistent with
similar transactions with nonaffiliated entities.





Other





Commodity
hedges.An affiliate of Merrill Lynch, Pierce, Fenner & Smith
Incorporated (“Merrill Lynch”) holds an equity interest in Targa Investments,
which indirectly owns our general partner. We have entered into various
commodity derivative transactions with Merrill Lynch Commodities Inc. (“MLCI”)
an affiliate of Merrill Lynch. The following table shows our open commodity
derivatives with MLCI as of December 31, 2008:


F-27
 TABLE OF CONTENTS





InstrumentPeriod
                Commodity
                Type
                
                Daily Volumes
                
                Average Price
                IndexJan
      2009 - Dec 2009
                Natural
      gas
                Swap
                
                
                3,556
                
                MMBtu
                
                $
                8.07
                
                per
      MMBtu
                IF-WahaJan
      2009 - Dec 2009
                Natural
      gas
                Swap
                
                
                575
                
                MMBtu
                
                
                7.83
                
                per
      MMBtu
                NY-HHJan
      2010 - Dec 2010
                Natural
      gas
                Swap
                
                
                3,289
                
                MMBtu
                
                
                7.39
                
                per
      MMBtu
                IF-WahaJan
      2010 - Dec 2010
                Natural
      gas
                Swap
                
                
                247
                
                MMBtu
                
                
                8.17
                
                per
      MMBtu
                NY-HHJan
      2009 - Dec 2009
                NGL
                Swap
                
                
                3,000
                
                Bbl
                
                
                1.18
                
                per
      gallon
                OPIS-MBJan
      2009 - Dec 2009
                Condensate
                Swap
                
                
                202
                
                Bbl
                
                
                70.60
                
                per
      barrel
                NY-WTIJan
      2010 - Dec 2010
                Condensate
                Swap
                
                
                181
                
                Bbl
                
                
                69.28
                
                per
      barrel
                NY-WTI





As of
December 31, 2008, the fair value of these open positions is $32.0 million.
During 2008, 2007 and 2006, we paid to (received from) MLCI $9.1 million, $1.9
million and $(4.2) million in commodity derivative settlements.








Note
11—Commitments and Contingencies





Future
non-cancelable commitments related to certain contractual obligations are
presented below.





Payments Due by PeriodTotal
                  
                  
                  2009
                  
                  
                  2010
                  
                  
                  2011
                  
                  
                  2012
                  
                  
                  2013
                  
                  
                  Thereafter(In
      thousands)Capacity
      payments
                  
                  $
                  8,215
                  
                  
                  $
                  5,419
                  
                  
                  $
                  2,050
                  
                  
                  $
                  746
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  -Right-of-way
                  
                  
                  4,889
                  
                  
                  
                  348
                  
                  
                  
                  331
                  
                  
                  
                  330
                  
                  
                  
                  319
                  
                  
                  
                  233
                  
                  
                  
                  3,328$
                  13,104
                  
                  
                  $
                  5,767
                  
                  
                  $
                  2,381
                  
                  
                  $
                  1,076
                  
                  
                  $
                  319
                  
                  
                  $
                  233
                  
                  
                  $
                  3,328





Total
expenses related to operating lease obligations, capacity payments and
right-of-way payments were $5.9 million, $5.7
million and $3.2 million for 2008, 2007 and 2006.





Environmental





Under the
Omnibus Agreement described in Note 10, Targa has 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 was less than $0.1 million as of December
31, 2008.





Litigation





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 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 and the appeal
is pending before the 14th Court
of Appeals in Houston, TX.  We are contesting WTG’s appeal, but can
give no assurances regarding the outcome of the proceeding. Targa has agreed to
indemnify us for any claim or liability arising out of the WTG
suit.


F-28
 TABLE OF CONTENTS








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.








Note
12—Fair Valueof 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 amounts and fair values of our other financial
instruments are as follows as of the dates indicated.




The
carrying value of the credit facility approximates its fair value, as its
interest rate is based on prevailing market rates. The fair value of the senior
notes is based on quoted market prices based on trades of such
debt.





As of December 31,2008
                
                
                2007Carrying
                
                
                Fair
                
                
                Carrying
                
                
                FairAmount
                
                
                Value
                
                
                Amount
                
                
                Value(In
      thousands)Credit
      facility
                
                $
                487,765
                
                
                $
                487,765
                
                
                $
                626,300
                
                
                $
                626,300Senior
      unsecured notes
                
                
                209,080
                
                
                
                128,333
                
                
                
                -
                
                
                
                -








Note
13—Fair Value Measurements





SFAS 157
established a three-tier fair value hierarchy, which prioritized the 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 either readily available in public markets or
are quoted by counterparties to these contracts. In situations where we obtain
inputs via quotes from our counterparties, we verify the reasonableness of these
quotes via similar quotes from another source for each date for which financial
statements are presented. 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. The price
quotes for the Level 3 inputs are provided by a counterparty with whom we
regularly transact business.





F-29
 TABLE OF CONTENTS


The
following table sets 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, 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.








Total
                
                
                Level 1
                
                
                Level 2
                
                
                Level 3(In
      thousands)Assets
      from commodity derivative contracts
                
                $
                160,112
                
                
                $
                -
                
                
                $
                36,808
                
                
                $
                123,304Assets
      from interest rate derivatives
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -Total
      assets
                
                $
                160,112
                
                
                $
                -
                
                
                $
                36,808
                
                
                $
                123,304Liabilities
      from commodity derivative contracts
                
                $
                3,767
                
                
                $
                -
                
                
                $
                3,767
                
                
                $
                -Liabilities
      from interest rate derivatives
                
                
                17,576
                
                
                
                -
                
                
                
                17,576
                
                
                
                -Total
      liabilities
                
                $
                21,343
                
                
                $
                -
                
                
                $
                21,343
                
                
                $
                -





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 Contracts(In
      thousands)Balance,
      December 31, 2007
                
                $
                (71,370
                )Total
      gains (losses) realized/unrealizedIncluded
      in loss on mark-to-market derivatives
                
                
                (991
                )Included
      in OCI
                
                
                100,068Purchases
                
                
                2,866Terminations
                
                
                77,792Settlements
                
                
                14,939Balance,
      December 31, 2008
                
                $
                123,304





No
unrealized gains or losses were reported relating to assets and liabilities
still held as of December 31, 2008.








Note
14— Significant Risksand Uncertainties





Nature
of Operations in Midstream Energy Industry





We
operate in the midstream energy industry. Our business activities include
gathering, transporting and processing of natural gas, NGLs and crude oil. As
such, 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, crude oil 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 crude oil transported, gathered or processed at our facilities. A material
decrease in natural gas or crude oil production or crude oil 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 crude oil 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-30
 TABLE OF CONTENTS





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.





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
11.





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-31
 TABLE OF CONTENTS


Note
15— SelectedQuarterly Financial Data
(Unaudited)





Our
results of operations by quarter for the years ended December 31, 2008 and 2007,
as adjusted to reflect the consideration of common control accounting and change
in predecessor entities as discussed in Note 1, were as follows:








First
                    Quarter
                  
                  
                  Second
                    Quarter
                  
                  
                  Third
                    Quarter
                  
                  
                  Fourth
                    Quarter
                  
                  
                  Total(In
      thousands, except per unit amounts)Year
      Ended December 31, 2008:Revenues
                  
                  $
                  512,069
                  
                  
                  $
                  630,520
                  
                  
                  $
                  578,747
                  
                  
                  $
                  352,782
                  
                  
                  $
                  2,074,118Operating
      income
                  
                  
                  33,974
                  
                  
                  
                  36,525
                  
                  
                  
                  26,815
                  
                  
                  
                  21,720
                  
                  
                  
                  119,034Net
      income per common and subordinated unit
                  
                  
                  24,935
                  
                  
                  
                  28,206
                  
                  
                  
                  14,692
                  
                  
                  
                  23,661
                  
                  
                  
                  91,494Net
      income per unitBasic
                  
                  $
                  0.50
                  
                  
                  $
                  0.54
                  
                  
                  $
                  0.31
                  
                  
                  $
                  0.48
                  
                  
                  $
                  1.83Diluted
                  
                  $
                  0.50
                  
                  
                  $
                  0.54
                  
                  
                  $
                  0.31
                  
                  
                  $
                  0.48
                  
                  
                  $
                  1.83Year
      Ended December 31, 2007:Revenues
                  
                  $
                  348,781
                  
                  
                  $
                  433,615
                  
                  
                  $
                  405,038
                  
                  
                  $
                  474,035
                  
                  
                  $
                  1,661,469Operating
      income
                  
                  
                  20,739
                  
                  
                  
                  28,183
                  
                  
                  
                  29,965
                  
                  
                  
                  34,467
                  
                  
                  
                  113,354Net
      income (loss) per common and subordinated unit
                  
                  
                  (10,627
                  )
                  
                  
                  13,811
                  
                  
                  
                  14,392
                  
                  
                  
                  22,674
                  
                  
                  
                  40,250Net
      income per unitBasic
                  
                  $
                  0.07
                  
                  
                  $
                  0.13
                  
                  
                  $
                  0.12
                  
                  
                  $
                  0.42
                  
                  
                  $
                  0.81Diluted
                  
                  $
                  0.07
                  
                  
                  $
                  0.13
                  
                  
                  $
                  0.12
                  
                  
                  $
                  0.42
                  
                  
                  $
                  0.81








F-32
 TABLE OF CONTENTS


Index
to Exhibits




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




2.2
            Amendment
      to Purchase and Sale Agreement, dated October 1, 2007, by and between
      Targa Resources Holdings LP and Targa Resources Partners LP (incorporated
      by reference to Exhibit 2.2 to Targa Resources Partners LP’s Current
      Report on Form 8-K filed October 24, 2007 (File No.
      001-33303)).




3.1
            Certificate
      of Limited Partnership of Targa Resources Partners LP (incorporated by
      reference to Exhibit 3.2 to Targa Resources Partners LP’s Registration
      Statement on Form S-1 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)).




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
            Registration
      Rights Agreement dated June 18, 2008, among Targa Resources Partners LP,
      Targa Resources Partners Finance Corporations, 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 June 18, 2008 (File No.
  001-33303)).




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




10.2
            Commitment
      Increase Supplement, dated October 24, 2007, by and among Targa Resources
      Partners LP, Bank of America, N.A. and the parties signatory thereto as
      the Increasing Lenders and the New Lenders (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)).




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




10.4
            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
            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)).




10.6
            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)).




10.7
            Amended
      and Restated Omnibus Agreement, dated October 24, 2007, by and among Targa
      Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and
      Targa Resources GP LLC (incorporated by reference to Exhibit 10.5 to Targa
      Resources Partners LP’s Current Report on Form 8-K filed October 24, 2007
      (File No. 001-33303)).




10.8+
            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)).




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




10.10+*
            Amendment
      to Targa Resources Partners LP Long-Term Incentive Plan dated December 18,
      2008.




10.11+
            Form
      of Restricted Unit Grant Agreement (incorporated by reference to Exhibit
      10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed
      October 24, 2007 (File No.
001-33303)).




10.12+
            Form
      of Performance Unit Grant Agreement (incorporated by reference to Exhibit
      10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed
      January 28, 2009 (File No.
001-33303)).




10.13+*
            Targa
      Resources Investments Inc. 2008 Annual Incentive Compensation
      Plan




10.14+*
            Targa
      Resources Investments Inc. 2009 Annual Incentive Compensation
      Plan




10.15
            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)).




10.16
            Natural
      Gas Purchase Agreement, effective January 1, 2007, by and between Targa
      Gas Marketing LLC (Buyer) and Targa North Texas LP (Seller) (incorporated
      by reference to Exhibit 10.11 to Targa Resources Partners LP’s
      Registration Statement on Form S-1 filed October 1, 2007 (File No.
      333-146436)).




10.17
            NGL
      and Condensate Purchase Agreement, effective January 1, 2007, by and
      between Targa North Texas LP (Seller) and Targa Liquids Marketing and
      Trade (Buyer) (incorporated by reference to Exhibit 10.12 to Targa
      Resources Partners LP’s Registration Statement on Form S-1 filed October
      1, 2007 (File No. 333-146436)).




10.18
            Product
      Purchase Agreement, effective January 1, 2007, by and between Targa
      Louisiana Field Services LLC (Seller) and Targa Liquids Marketing and
      Trade (Buyer) (incorporated by reference to Exhibit 10.13 to Targa
      Resources Partners LP’s Registration Statement on Form S-1/A filed October
      12, 2007 (File No. 333-146436)).




10.19
            Raw
      Product Purchase Agreement, effective January 1, 2007, by and between
      Targa Texas Field Services LP (Seller) and Targa Liquids Marketing and
      Trade (Buyer) (incorporated by reference to Exhibit 10.14 to Targa
      Resources Partners LP’s Registration Statement on Form S-1/A filed October
      12, 2007 (File No. 333-146436)).




10.20
            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)).




10.21
            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)).




10.22
            Amended
      and Restated Natural Gas Purchase Agreement, effective December 1, 2005,
      by and between Targa Gas Marketing LLC (Buyer) and Targa Texas Field
      Services LP (Seller) (incorporated by reference to Exhibit 10.17 to Targa
      Resources Partners LP’s Registration Statement on Form S-1/A filed October
      12, 2007 (File No. 333-146436)).




10.23+
            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)).




10.24+
            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)).




10.25+
            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)).




10.26
            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.




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.





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 TABLE OF CONTENTS