Targa Resources Partners (NGLS-PA) 10-K 2009 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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

For the fiscal year ended December 31, 2009

or

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

For the transition period from                     to

Commission file number: 001-33303

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware	65-1295427
(State or other jurisdiction of
incorporation or organization)	(I.R.S. Employer
	Identification No.)
1000 Louisiana St, Suite 4300
Houston, 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 Registered
Common Units Representing Limited Partnership Interests	New York Stock Exchange

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

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

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

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

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

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

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

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

(Do not check if a smaller reporting company)

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

Act). Yes £ No R.

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

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

DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS
DESCRIPTION
PART I
	1.	BUSINESS	4
	1A.	RISK FACTORS	25
	1B.	UNRESOLVED STAFF COMMENTS	47
	2.	PROPERTIES	47
	3.	LEGAL PROCEEDINGS	47
	4.	RESERVED	47
PART II
	5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
		ISSUER PURCHASES OF EQUITY SECURITIES	48
	6.	SELECTED FINANCIAL DATA	49
	7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
		OF OPERATIONS	55
	7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	80
	8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	83
	9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
		FINANCIAL DISCLOSURE	83
	9A.	CONTROLS AND PROCEDURES	83
	9B.	OTHER INFORMATION	84
PART III
	10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	85
	11.	EXECUTIVE COMPENSATION	90
	12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
		RELATED STOCKHOLDER MATTERS	106
	13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	108
	14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	113
PART IV
	15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	114

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Part I

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

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

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

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

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

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

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

· the level of creditworthiness of counterparties to transactions;

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

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

· weather and other natural phenomena;

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

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

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

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

· general economic, market and business conditions; and

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

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

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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
Btu	British thermal units, a measure of heating value
/d	Per day
gal	Gallons
MBbl	Thousand barrels
Mcf	Thousand cubic feet
MMBbl	Million barrels
MMBtu	Million British thermal units
MMcf	Million cubic feet
NGL	Natural gas liquid(s)
Price Index Definitions
IF-NGPL MC	Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
IF-Waha	Inside FERC Gas Market Report, West Texas Waha
NY-WTI	NYMEX, West Texas Intermediate Crude Oil
OPIS-MB	Oil Price Information Service, Mont Belvieu, Texas

Item 1. Business

Overview

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

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

Natural Gas Gathering and Processing

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

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

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

NGL Logistics and Marketing

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

Business Strategies

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

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

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

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

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

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

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

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

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

Competitive Strengths

We believe that we are well positioned to execute our primary business objective and business strategies successfully because of the following competitive strengths:

Affiliation with Targa.We expect that our relationship with Targa will provide us with significant business opportunities. We believe Targa’s relationships throughout the energy industry, including with producers of natural gas in the U.S., will help facilitate implementation of our acquisition strategy and other strategies. Targa has indicated that it intends to use us as a growth vehicle to pursue the acquisition and expansion of midstream natural gas, NGL and other complementary energy businesses and assets and we expect to have the opportunity, but not the obligation, to acquire such businesses and assets directly from Targa in the future. Our relationship with Targa provides us access to its extensive pool of operational, commercial and risk management expertise which enables all of our strategies.

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

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

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

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

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

Attractive Cash Flow Characteristics

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

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

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

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

Asset Base Well-Positioned for Organic Growth

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

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

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

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

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

Our Business

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

Natural Gas Gathering and Processing Division

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

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

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

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

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

Facility	Location	Gross Throughput Capacity (MMcf/d)		2009 Plant Natural Gas Inlet (MMcf/d)		2009 Gross NGL Production (MBbl/d)
North Texas System
Chico (1)	Wise, TX		265.0
Shackelford	Shackelford,TX		13.0
	Area Total		278.0		173.6		20.1
SAOU System
Mertzon	Irion, TX		48.0
Sterling	Sterling, TX		62.0
Conger (2)	Sterling, TX		25.0
	Area Total		135.0		91.5		14.1
LOU System
Gillis (1)	Calcasieu, LA		180.0
Acadia	Acadia, LA		80.0
	Area Total		260.0		180.8		8.5
			673.0		445.9		42.7

_______

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

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

North Texas System

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

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

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

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

SAOU System

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

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

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

LOU System

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

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

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

NGL Logistics and Marketing Division

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

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

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Logistics Assets Segment

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

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

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

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

The following table details our fractionation facilities:

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

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

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

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

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

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

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

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

The following tables detail our NGL storage and terminalling assets:

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

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

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

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

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

(2)      Volumes reflect total transport and injection volumes.

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

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

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

· approximately 850 railcars that we lease and manage;

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

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

NGL Distribution and Marketing Segment

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

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

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Wholesale Marketing Segment

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

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

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

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

Operational Risks and Insurance

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

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

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Significant Customers

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

	2009		2008		2007
% of consolidated revenues
CPC		17%		20%		22%
% of consolidated product purchases
Louis Dreyfus Energy Services L.P.		12%		9%		7%

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

Competition

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

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

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

Regulation of Operations

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

Gathering Pipeline Regulation

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

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

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

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

Intrastate Pipeline Regulation

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

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

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

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

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

Regulation of our NGL intrastate pipelines

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

Natural Gas Processing

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

Availability, Terms and Cost of Pipeline Transportation

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

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

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

Sales of Natural Gas and NGLs

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

Other State and Local Regulation of Our Operations

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

Interstate common carrier liquids pipeline regulation

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

Other Federal Laws and Regulation Affecting Our Industry

Energy Policy Act of 2005

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

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

FERC Standards of Conduct for Transmission Providers

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

FERC Market Transparency Rules

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

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

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

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

Environmental, Health and Safety Matters

General

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

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

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

Hazardous Substances and Waste

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

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

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

Air Emissions

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

Climate Change

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

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

Water Discharges

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

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

Endangered Species Act

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

Pipeline Safety

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

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

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

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

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

Employee Health and Safety

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

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Title to Properties and Rights-of-Way

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

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

Employees

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

Financial Information by Segment

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

Available Information

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

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Item 1A. Risk Factors 

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

Risks Related to Our Business

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

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

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

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

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

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

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

Our substantial indebtedness may:

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

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

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

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

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

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

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

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

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

Our cash flow is affected by supply and demand for natural gas and NGL products and by natural gas and NGL prices and decreases in these prices could adversely affect our ability to make distributions to holders of our common units.

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

· the impact of seasonality and weather;

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

· the economic conditions of our customers;

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

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

· actions taken by foreign oil and gas producing nations;

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

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

· the impact of energy conservation efforts; and

· the extent of governmental regulation and taxation.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

If we do not make acquisitions on economically acceptable terms or efficiently and effectively integrate the acquired assets with our asset base, our future growth will be limited.

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

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

· operating a significantly larger combined organization and adding operations;

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

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

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

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

· coordinating geographically disparate organizations, systems and facilities.

· the assumption of unknown liabilities;

· limitations on rights to indemnity from the seller;

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

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

· customer or key employee losses at the acquired businesses.

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

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

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

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

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

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

We are exposed to the credit risk of Targa and any material nonperformance by Targa could reduce our ability to make distributions to our unitholders.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Increases in interest rates could adversely affect our business.

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

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Restrictions in our credit facility may interrupt distributions to us from our subsidiaries, which may limit our ability to make distributions to you, satisfy our obligations and capitalize on business opportunities.

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

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

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

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

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

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

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

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

 A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

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

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

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

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

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

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

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

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

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

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

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stations, processing facilities and fractionators or from the combustion of natural gas or natural gas liquids that we produce could increase our costs of doing business and/or increase the cost and reduce demand for our services.

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

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

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

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

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

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

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

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

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

· perform ongoing assessments of pipeline integrity;

· identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

· improve data collection, integration and analysis;

· repair and remediate the pipeline as necessary; and

· implement preventive and mitigating actions.

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

Our construction of new assets may not result in revenue increases and is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

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

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

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

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

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

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

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

Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.

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

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

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

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Risks Inherent in an Investment in Us

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

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

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

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

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

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

· the relationship between natural gas and NGL prices;

· cash settlements of hedging positions;

· the level of competition from other midstream energy companies;

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

· prevailing economic conditions.

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

· the level of capital expenditures we make;

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

· the cost of acquisitions;

· our debt service requirements and other liabilities;

· fluctuations in our working capital needs;

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

· restrictions on distributions contained in our debt agreements;

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

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

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

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

· neither our partnership agreement nor any other agreement requires Targa to pursue a business strategy that favors us. Targa’s directors and officers have a fiduciary duty to make decisions in the best interests of the owners of Targa, which may be contrary to our interests; and

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

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

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

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

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

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

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

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

· permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires and it has no duty or obligation to give any consideration to any interest of or factors affecting, us, our affiliates or any limited partner;

· provides that our general partner does not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;

· generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

· provides that our general partner and its officers and directors are not liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and nonappealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

· provides that in resolving conflicts of interest, it is presumed that in making its decision the general partner acted in good faith and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Cost reimbursements due our general partner and its affiliates for services provided, which will be determined by our general partner, will be substantial and will reduce our cash available for distribution to you.

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

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

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

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

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

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

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

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

· the ratio of taxable income to distributions may increase;

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

· the market price of the common units may decline.

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

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

Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of our general partner or holders of our common units. This ability may result in lower distributions to holders of our common units in certain situations.

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

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

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

Increases in interest rates could adversely impact our unit price and our ability to issue additional equity to make acquisitions, for expansion capital expenditures or for other purposes.

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

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

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

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

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

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

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

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

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

· a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

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

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

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

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”), were to treat us as a corporation for federal income tax purposes or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to you would be substantially reduced.

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

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

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

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

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Our 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. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Although existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued.

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

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

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

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

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

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

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

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

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

We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

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

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

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

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

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

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

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

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

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

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

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

Item 1B. Unresolved Staff Comments

None

Item 2. Properties

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

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

Item 3. Legal Proceedings

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

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

Item 4. Reserved

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PART II

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

Market Information

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

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

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

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

Distributions of Available Cash

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

Definition of Available Cash. The term “available cash,” for any quarter, means all cash and cash equivalents on hand on the date of determination of available cash for that quarter less the amount of cash reserves established by our general partner to:

· provide for the proper conduct of our business;

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

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

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

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

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

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

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

Recent Sales of Unregistered Units

None

Repurchase of Equity by Targa Resources Partners LP

None

Item 6. Selected Financial Data

SELECTED FINANCIAL AND OPERATING DATA

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

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

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

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

_______

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

(2)   During 2009, we reclassified NGL marketing fractionation and other service fees to revenues that were originally recorded in product purchase costs. The reclassification increased revenues and product purchases for 2008, 2007, 2006 and 2005 by $28.7 million, $27.6 million, $20.3 million and $3.9 million.

(3)   Operating margin is total operating revenues less product purchases and operating expense. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations—Operating Margin” and “Non-GAAP Financial Measures.”

(4)   Adjusted EBITDA is net income before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations—Adjusted EBITDA” and “Non-GAAP Financial Measures.”

(5)   Distributable Cash Flow is net income plus depreciation and amortization and deferred taxes, adjusted for losses/(gains) on mark-to-market derivative contracts and debt repurchases, less maintenance capital expenditures. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations—Distributable Cash Flow” and “Non-GAAP Financial Measures.”

(6) Gathering throughput represents the volume of natural gas gathered and passed through natural gas gathering pipelines from connections to producing wells and central delivery points.

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

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

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

Non-GAAP Financial Measures

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

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

· our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

· the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

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

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

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

________

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

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

________

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

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

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

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

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

· our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

· the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

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

_______

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

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

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

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

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

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

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

_______

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

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

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

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

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

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

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

Overview

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

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

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

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

Factors That Significantly Affect Our Results

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Distributions to our Unitholders

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

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

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

_______

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

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

General Trends and Outlook

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

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

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

	2009		2008		2007
% of consolidated revenues
CPC		17%		20%		22%
% of consolidated product purchases
Louis Dreyfus Energy Services L.P.		12%		9%		7%

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

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

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

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

How We Evaluate Our Operations

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

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

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

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

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

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

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

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

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

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

 ________

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

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

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

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

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

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· our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

· the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

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

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

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

· our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

· the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

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

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

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

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

_______

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

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

_______

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

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

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

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

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

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

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

_______

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

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Results of Operations

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

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

 _______

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

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

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

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

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

(6) Gathering throughput represents the volume of natural gas gathered and passed through natural gas gathering pipelines from connections to producing wells and central delivery points.

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

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

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

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

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

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

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

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

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

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

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

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

Loss on debt repurchases of $1.5 million for 2009 relates to open market repurchases of our 11¼% Senior Notes due 2017.

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

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

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

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

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

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

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

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

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

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

Gain on debt repurchases of $13.1 million for 2008 relates to open market repurchases of our 8¼% Senior Notes due 2016.

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

Results of Operations—By Segment

Natural Gas Gathering and Processing Segment

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

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

_______

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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Logistics Assets Segment

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

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

_______

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

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

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

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

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

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

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

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NGL Distribution and Marketing Services Segment

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

	Year Ended December 31,
	2009			2008			2007
	($ in millions)
NGL sales revenues	$	2,907.7		$	5,172.2		$	4,889.3
Other revenues (1)		28.5			41.2			34.1
		2,936.2			5,213.4			4,923.4
Product purchases		(2,890.1	)		(5,193.2	)		(4,866.4	)
Operating expenses		(0.3	)		(1.7	)		(1.5	)
Operating margin (2)	$	45.8		$	18.5		$	55.5
Operating statistics:
NGL sales, MBbl/d		245.7			244.6			275.6
NGL realized price, $/gal		0.77			1.38			1.16

_______

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

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

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

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

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

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

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

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

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

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Wholesale Marketing Segment

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

	Year Ended December 31,
	2009			2008			2007
	($ in millions)
NGL sales revenues	$	884.7		$	1,453.3		$	1,294.7
Other revenues (1)		1.3			6.8			1.3
		886.0			1,460.1			1,296.0
Product purchases		(862.3	)		(1,446.9	)		(1,273.1	)
Operating expenses		-			(0.1	)		(0.1	)
Operating margin (2)	$	23.7		$	13.1		$	22.8
Operating statistics:
NGL sales, MBbl/d		58.8			62.5			63.6
NGL realized price, $/gal		0.98			1.51			1.33

_______

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

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

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

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

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

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

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

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

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

Insurance Claims

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

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

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

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

Liquidity and Capital Resources

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

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

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

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

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

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

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

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

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

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

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

Cash Flow

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

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

Operating Activities

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

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

Investing Activities

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

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

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

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

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Financing Activities

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

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

Capital Requirements

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

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

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

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

Credit Facilities and Long-Term Debt

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

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

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Description of 8¼% Senior Notes. On June 18, 2008, we completed the private placement under Rule 144 A and Regulation S of the Securities Act of 1933 of $250 million in aggregate principal amount of our 8¼% senior unsecured notes due 2016 (the “8¼% Notes”). In connection with the issuance of the 8¼% Notes, we entered into an indenture (the “2008 Indenture”) governing the terms of the 8¼% Notes.

The 8¼% Notes will mature on July 15, 2016 and interest is payable on the 8¼% Notes semi-annually in arrears on each January 1 and July 1. The 8¼% Notes are guaranteed on a senior unsecured basis by certain of our subsidiaries.

The 2008 Indenture restricts our ability to make distributions to unitholders if we are in default or an event of default (as defined in the 2008 Indenture) exists. It also restricts our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay certain distributions on or repurchase, equity interests (only if such distributions do not meet specified conditions); (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 8¼% Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the 2008 Indenture) has occurred and is continuing, many of such covenants will terminate and we and our subsidiaries will cease to be subject to such covenants.

Description of 11¼% Senior Notes. On July 6, 2009, we completed the private placement under Rule 144A and Regulation S of the Securities Act of 1933 of $250 million in aggregate principal amount of 11¼% senior notes due 2017 (the “11¼% Notes”). The 11¼% Notes were issued at 94.973% of the face amount, resulting in gross proceeds of $237.4 million. Proceeds from the 11¼% Notes were used to repay borrowings under our senior secured revolving credit facility. In connection with the issuance of the 11¼% Notes, we entered into an indenture (the “2009 Indenture”) governing the terms of the 11¼% Notes.

The 11¼% Notes will mature on July 1, 2017 and interest is payable on the 11¼% Notes semi-annually in arrears on each January 15 and July 15. The 11¼% Notes are guaranteed on a senior unsecured basis by certain of our subsidiaries.

The 2009 Indenture restricts our ability to make distributions to unitholders if we are in default or an event of default (as defined in the 2009 Indenture) exists. It also restricts our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay certain distributions on or repurchase, equity interests (only if such distributions do not meet specified conditions); (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 11¼% Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the 2009 Indenture) has occurred and is continuing, many of such covenants will terminate and we and our subsidiaries will cease to be subject to such covenants.

Off-Balance Sheet Arrangements

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

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Contractual Obligations

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

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

________

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

Critical Accounting Policies and Estimates

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

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

· changes in energy prices;

· changes in competition;

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

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· changes in technology that render an asset obsolete;

· changes in expected salvage values; and

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

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

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

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

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

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

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

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

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

Recent Accounting Pronouncements.

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

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

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

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

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

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

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

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

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

Natural Gas

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

NGL

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

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Condensate

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

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

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

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

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

Period	Fixed Rate		Notional Amount	Fair Value
				(In millions)
2010		3.67%	$300 million	$	(7.8	)
2011		3.52%	300 million		(5.1	)
2012		3.40%	300 million		(0.6	)
2013		3.39%	300 million		1.6
01/01 - 4/24/2014		3.39%	300 million		1.3
				$	(10.6	)

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

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

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

Item 8. Financial Statements and Supplementary Data

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

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

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

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

Internal Control Over Financial Reporting

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

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

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The effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2009, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in itsreport included in our Consolidated Financial Statements on page F-3 of this Annual Report, which is incorporated herein by reference.

(b) Changes in Internal Control Over Financial Reporting

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

Item 9B. Other Information

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

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Part III

Item 10. Directors, Executive Officers and Corporate Governance

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

Management of Targa Resources Partners LP

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

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

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

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

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

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

Directors and Executive Officers

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

Name	Age (1)		Position with Targa Resources GP LLC
Rene R. Joyce		62	Chief Executive Officer and Director
Joe Bob Perkins		49	President
James W. Whalen		68	President — Finance and Administration and Director
Roy E. Johnson		65	Executive Vice President
Michael A. Heim		61	Executive Vice President and Chief Operating Officer
Jeffrey J. McParland		55	Executive Vice President and Chief Financial Officer
Paul W. Chung		49	Executive Vice President, General Counsel and Secretary
Peter R. Kagan		41	Director
Chansoo Joung		49	Director
Robert B. Evans		61	Director
Barry R. Pearl		60	Director
William D. Sullivan		53	Director

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(1) As of February 25, 2010

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

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

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

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

Roy E. Johnson has 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. Heim has 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. McParland has 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.

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

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

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

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

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

Reimbursement of Expenses of Our General Partner

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

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

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

Corporate Governance

Code of Ethics

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

Available Information

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

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

Executive Sessions of Non-Management Directors

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

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

Section 16(A) Beneficial Ownership Reporting Compliance

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

Item 11. Executive Compensation

Executive Compensation

Compensation Discussion and Analysis

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

Overview

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

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

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

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

Compensation Philosophy

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

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

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

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

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

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

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

The Role of Peer Groups and Benchmarking

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

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

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

Role of Senior Management in Establishing Compensation for Named Executive Officers

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

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

Elements of Compensation for Named Executive Officers

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

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

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

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

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

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

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

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

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

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

Relation of Compensation Elements to Compensation Philosophy

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

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

Application of Compensation Elements

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

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

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

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

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

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

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

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

	Performance (1)
Grant	Peer Group Median		Partnership		Partnership Position
2008		7.9%		15.2%	5th of 13
2009		53.1%		79.6%	3rd of 13

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

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

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

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

Changes for 2010

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

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

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

Compensation Committee Interlocks and Insider Participation

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

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

Compensation Committee Report

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

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

Rene R. Joyce

James W. Whalen

Peter R. Kagan

Chansoo Joung

Robert B. Evans

Barry R. Pearl

William D. Sullivan

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Executive Compensation

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

	Summary Compensation Table for 2009
						Non-Equity
				Stock		Incentive Plan		All Other		Total
Name	Year	Salary		Awards ($)(1)		Compensation		Compensation (2)		Compensation
Rene R. Joyce	2009	$	337,500	$	742,965	$	510,000	$	20,187	$	1,610,652
Chief Executive Officer	2008		322,500		148,218		247,500		19,205		737,423
	2007		293,750		459,769		300,000		817,963		1,871,482
Jeffrey J. McParland	2009		265,000		435,695		400,500		20,061		1,121,256
Executive Vice President and	2008		253,000		114,247		194,250		19,031		580,528
Chief Financial Officer	2007		230,000		316,770		235,000		674,292		1,456,062
Joe Bob Perkins	2009		303,750		574,514		459,000		20,129		1,357,393
President	2008		290,250		126,228		222,750		19,124		658,352
	2007		265,000		366,318		270,000		817,888		1,719,206
James W. Whalen	2009		297,000		306,914		445,500		19,936		1,069,350
President—Finance and	2008		290,250		66,488		222,750		18,871		598,359
Administration	2007		265,000		224,796		270,000		817,888		1,577,684
Michael A. Heim	2009		281,000		553,310		424,500		20,089		1,278,899
Executive Vice President and	2008		268,750		127,172		206,250		19,071		621,243
Chief Operating Officer	2007		243,750		366,318		250,000		817,838		1,677,906

_______

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

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

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

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Grants of Plan-Based Awards

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

	Grants of Plan Based Awards for 2009
			Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1)						Estimated Future Payouts Under Equity Incentive Plan Awards (2)				Grant Date Fair Value of Stock and Option Awards (3)
Name	Grant Date		Threshold		Target		2X Target		Threshold	Target (Units)		Maximum
Mr. Joyce		N/A	$	85,000	$	170,000	$	340,000
	01/22/09										34,000		$	1,249,068
	12/03/09										18,025			649,677
Mr. McParland		N/A		66,750		133,500		267,000
	01/22/09										15,500			569,428
	12/03/09										9,350			337,003
Mr. Perkins		N/A		76,500		153,000		306,000
	01/22/09										20,800			764,136
	12/03/09										13,860			499,557
Mr. Whalen		N/A		74,250		148,500		297,000
	12/03/09										13,464			485,284
Mr. Heim		N/A		70,750		141,500		283,000
	01/22/09										20,800			764,136
	12/03/09										9,894			356,610

_______

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

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

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

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

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

Targa Investments 2005 Stock Incentive Plan

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

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

Outstanding Equity Awards at 2009 Fiscal Year-End

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

	Outstanding Equity Awards at 2009 Fiscal Year-End
	Option Awards					Stock Awards
Name	Options Exercisable		Option Exercise Price		Option Expiration Date	Equity Incentive Plan Awards:  Number of Unearned Performance Units That Have Not Vested(1)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Performance Units That Have Not Vested(2)
Rene R. Joyce		21,772	$	0.75	10/31/15		71,025	$	1,848,849
		291,376		3.00	10/31/15
		246,549		15.00	10/31/15
		3,006		3.00	12/20/15
		2,559		15.00	12/20/15
Jeffrey J. McParland		218,532		3.00	10/31/15		35,750		934,717
		184,912		15.00	10/31/15
		2,254		3.00	12/20/15
		1,919		15.00	12/20/15
Joe Bob Perkins		236,014		3.00	10/31/15		48,960		1,276,843
		199,705		15.00	10/31/15
		2,435		3.00	12/20/15
		2,073		15.00	12/20/15
James W. Whalen		90,908		3.00	11/01/15
		192,308		15.00	11/01/15		27,764		740,040
		937		3.00	12/20/15
		1,996		15.00	12/20/15
Michael A. Heim		21,772		0.75	10/31/15
		236,014		3.00	10/31/15		44,194		1,157,174
		199,705		15.00	10/31/15
		2,435		3.00	12/20/15
		2,073		15.00	12/20/15

_______

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

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

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Option Exercises and Stock Vested in 2009

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

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

_______

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

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

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

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

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

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

Change in Control and Termination Benefits

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

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

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

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

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

• Change of Control means, 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 Stock means 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 Event means 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;

• Cause means 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

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

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

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

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

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

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

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

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

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• Fair Market Value means 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.

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

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

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

_______

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

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

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

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

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

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Director Compensation

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

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

_______

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

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

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

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

Narrative to Director Compensation Table

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

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

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

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Changes for 2010

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

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

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

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

· each person who then beneficially owns 5% or more of the then outstanding units;

· all of the directors of Targa Resources GP LLC;

· each named executive officer of Targa Resources GP LLC, and;

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

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

_______

* Less than 1%

(1) Unless otherwise indicated, the address for all beneficial owners in this table is 1000 Louisiana, Suite 4300, Houston, Texas 77002. The nature of the beneficial ownership for all the equity securities is sole voting and investment power.

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

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

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

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

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

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

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

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

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

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

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

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

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

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

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

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

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

Distributions and Payments to Our General Partner and its Affiliates

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

Operational Stage
Distributions of available cash to our general partner	We will generally make cash distributions 98% to our
and its affiliates	limited partner unitholders pro rata, including our
	general partner and its management as the holders of
	20,406,248 common units, and 2% to our general
	partner. In addition, if distributions exceed the
	minimum quarterly distribution and other higher
	target distribution levels, our general partner will be
	entitled to increasing percentages of the distributions,
	up to 50% of the distributions above the highest
	target distribution level.

Assuming we have sufficient available cash to pay the

full minimum quarterly distribution on all of our

outstanding units for four quarters, our general

partner and its affiliates would receive an annual

distribution of approximately $1.7 million on their

general partner units and $27.5 million on their

common units.

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

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

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

Purchase and Sale Agreement

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

Agreements Relating to the Acquisition of the Downstream Business

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

Omnibus Agreement

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

Reimbursement of Operating and General and Administrative Expense

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

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

With respect to the North Texas System, prior to February 15, 2010, we reimbursed Targa for general and administrative expenses, which were capped at $5.0 million annually, subject to certain increases; and operating and certain direct expenses, which were not capped. With respect to the SAOU and LOU Systems and the Downstream Business, we reimbursed Targa for general and administrative expenses, which were not capped, allocated to the SAOU and LOU Systems and the Downstream Business according to Targa’s allocation practice; and operating and certain direct expenses, which were not capped.

During the nine-quarter period beginning with the fourth quarter of 2009 and continuing through the fourth quarter of 2011, Targa will provide distribution support to us in the form of a reduction in the reimbursement for general and administrative expense allocated to us if necessary (or make a payment to us, if needed) for a 1.0 times distribution coverage ratio, at the current distribution level of $0.5175 per limited partner unit, subject to maximum support of $8.0 million in any quarter. No distribution support was necessary for the fourth quarter of 2009.

Competition

Targa is not restricted, under either our partnership agreement or the Omnibus Agreement, from competing with us. Targa may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.

Indemnification

Under the Omnibus Agreement, we have agreed to indemnify Targa against environmental liabilities related to the North Texas System arising or occurring after February 14, 2007.

Additionally, Targa has agreed to indemnify us for losses relating to income tax liabilities attributable to pre-IPO operations that are not reserved on the books of the Predecessor Business of the North Texas System as of February 14, 2007. Targa does not have any obligation under this indemnification until our aggregate losses exceed $250,000. Targa’s obligation under this indemnification will terminate upon the expiration of any applicable statute of limitations. We will indemnify Targa for all losses attributable to the post-IPO operations of the North Texas System.

Contracts with Affiliates

Natural Gas Purchase Agreements. Both the North Texas System and the SAOU and LOU Systems have entered into market based natural gas purchase agreements with Targa Gas Marketing LLC. These agreements have an initial term of 15 years and automatically extend for a term of five years, unless the agreements are otherwise terminated by either party. Furthermore, either party may elect to terminate the agreements if either party ceases to be an affiliate of Targa. In addition, Targa manages the SAOU and LOU Systems’ natural gas sales to third parties under contracts that remain in the name of the SAOU and LOU Systems.

NGL Product Purchase Agreements for the Downstream Business. We have entered into product purchase agreements with Targa Midstream Services Limited Partnership, a wholly-owned subsidiary of Targa (“TMSLP”), and Targa Permian LP, an indirect, wholly-owned subsidiary of Targa (“Targa Permian”), pursuant to which we will purchase all volumes of NGLs that are owned or controlled by TMSLP and Targa Permian and not otherwise committed for sale to a third party, at a price based on the prevailing market price less transportation, fractionation and certain other fees. The product purchase agreements will have an initial term of 15 years and will automatically extend for a term of five years. Furthermore, either party may elect to terminate the agreement if either party ceases to be an affiliate of Targa. Each product purchase agreement is effective as of September 1, 2009.

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    Indemnification Agreements. In February 2007, Targa Resources GP LLC, our general partner and we entered into Indemnification Agreements (each, an “Indemnification Agreement”) with each independent director of Targa Resources GP LLC (each, an “Indemnitee”). Each Indemnification agreement provides that each of the Partnership and Targa Resources GP LLC will indemnify and hold harmless each Indemnitee against Expenses (as defined in the Indemnification Agreement) to the fullest extent permitted or authorized by law, including the Delaware Revised Uniform Limited Partnership Act and the Delaware Limited Liability Company Act in effect on the date of the agreement or as such laws may be amended to provide more advantageous rights to the Indemnitee. If such indemnification is unavailable as a result of a court decision and if we or Targa Resources GP LLC is jointly liable in the proceeding with the Indemnitee, we and Targa Resources GP LLC will contribute funds to the Indemnitee for his Expenses in proportion to relative benefit and fault of the Partnership or Targa Resources GP LLC on the one hand and Indemnitee on the other in the transaction giving rise to the proceeding.

Each Indemnification Agreement also provides that we and Targa Resources GP LLC will indemnify and hold harmless the Indemnitee against Expenses incurred for actions taken as a director or officer of the Partnership or Targa Resources GP LLC or for serving at the request of the Partnership or Targa Resources GP LLC as a director or officer or another position at another corporation or enterprise, as the case may be, but only if no final and non-appealable judgment has been entered by a court determining that, in respect of the matter for which the Indemnitee is seeking indemnification, the Indemnitee acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal proceeding, the Indemnitee acted with knowledge that the Indemnitee’s conduct was unlawful. The Indemnification Agreement also provides that we and Targa Resources GP LLC must advance payment of certain Expenses to the Indemnitee, including fees of counsel, subject to receipt of an undertaking from the Indemnitee to return such advance if it is it is ultimately determined that the Indemnitee is not entitled to indemnification.

In February 2007, Targa Resources Investments Inc., the indirect holder of all of Targa’s common units, entered into Indemnification Agreements (each, a “Parent Indemnification Agreement”) with each director and officer of Targa (each, a “Parent Indemnitee”), including Messrs. Joyce, Whalen, Kagan and Joung who serve as directors and/or officers of our general partner. Each Parent Indemnification Agreement provides that Targa Resources Investments Inc. will indemnify and hold harmless each Parent Indemnitee for Expenses (as defined in the Parent Indemnification Agreement) to the fullest extent permitted or authorized by law, including the Delaware General Corporation Law, in effect on the date of the agreement or as it may be amended to provide more advantageous rights to the Parent Indemnitee. If such indemnification is unavailable as a result of a court decision and if Targa Resources Investments Inc. and the Parent Indemnitee are jointly liable in the proceeding, Targa Resources Investments Inc. will contribute funds to the Parent Indemnitee for his Expenses in proportion to relative benefit and fault of Targa Resources Investments Inc. and Parent Indemnitee in the transaction giving rise to the proceeding.

Each Indemnification Agreement also provides that Targa Resources Investments Inc. will indemnify the Parent Indemnitee for monetary damages for actions taken as a director or officer of Targa Resources Investments Inc. or for serving at Targa’s request as a director or officer or another position at another corporation or enterprise, as the case may be but only if (i) the Parent Indemnitee acted in good faith and, in the case of conduct in his official capacity, in a manner he reasonably believed to be in the best interests of Targa Resources Investments Inc. and, in all other cases, not opposed to the best interests of Targa Resources Investments Inc. and (ii) in the case of a criminal proceeding, the Parent Indemnitee must have had no reasonable cause to believe that his conduct was unlawful. The Parent Indemnification Agreement also provides that Targa Resources Investments Inc. must advance payment of certain Expenses to the Parent Indemnitee, including fees of counsel, subject to receipt of an undertaking from the Parent Indemnitee to return such advance if it is it is ultimately determined that the Parent Indemnitee is not entitled to indemnification.

Relationships with Warburg Pincus LLC

Chansoo Joung and Peter Kagan, two of the directors of our general partner and Targa, are Managing Directors of Warburg Pincus LLC and are also directors of Broad Oak Energy, Inc. (“Broad Oak”) from whom we buy natural gas and NGL products. Affiliates of Warburg Pincus LLC own a controlling interest in Broad Oak. We purchased $9.7 million and $4.8 million of product from Broad Oak during 2009 and 2008. These transactions were at market prices consistent with similar transactions with nonaffiliated entities.

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Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Targa) on the one hand and our partnership and our limited partners, on the other hand. The directors and officers of Targa Resources GP LLC have fiduciary duties to manage Targa and our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.

Whenever a conflict arises between our general partner or its affiliates, on the one hand and us or any other partner, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.

Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:

· approved by the conflicts committee, although our general partner is not obligated to seek such approval;

· approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

· on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

· fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of its board of directors. If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third or fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to believe he is acting in the best interests of the partnership.

Review, Approval or Ratification of Transactions with Related Persons

If a conflict or potential conflict of interest arises between our general partner and its affiliates (including Targa) on the one hand and our partnership and our limited partners, on the other hand, the resolution of any such conflict or potential conflict is addressed as described under “Conflicts of Interest.”

Pursuant to Targa’s Code of Conduct, our officers and directors are required to abandon or forfeit any activity or interest that creates a conflict of interest between them and Targa or any of its subsidiaries, unless the conflict is pre-approved by the Board of Directors.

Director Independence

The NYSE does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating/governance committee. Our general partner has a standing Audit Committee that consists of three directors: Messrs. Evans, Pearl and Sullivan. The board of directors of our general partner has affirmatively determined that Messrs. Evans, Pearl

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  and Sullivan are independent as described in the rules of the NYSE and the Exchange Act for purposes of serving on the board of directors and the Audit Committee.

The board of directors of our general partner examined the relationship between Targa and its subsidiaries and each of Legacy Reserves LP (“Legacy”) and St. Mary Land & Exploration Company (“St. Mary”). William D. Sullivan, one of our general partner’s directors, is a director of each of Legacy Reserves GP, LLC, Legacy’s general partner, and St. Mary. The Board determined that the relationship was not material since (i) the amounts involved were a small percentage of the total revenues of Targa, the Partnership and each of Legacy and St. Mary and (ii) the payments to Targa and the Partnership were for gas gathering and processing arrangements in the ordinary course of business. The relationship is consistent with Mr. Sullivan’s status as an independent director.

To be independent under the NYSE rules, a company’s board of directors must affirmatively determine that the director has no material relationship with the company (either directly or as a partner, stockholder or officer of an organization that has a relationship with the company). The board of directors of our general partner has made no such determination with respect to Messrs. Joyce, Kagan, Joung and Whalen because the NYSE rules do not require us to have a majority of independent directors. As such, Messrs. Joyce, Kagan, Joung and Whalen are not independent under NYSE rules applicable to service on a compensation and nominating/governance committee.

Item 14. Principal Accountant Fees and Service

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

	Year Ended December 31,
	2009		2008
	(In millions)
Audit Fees (1)	$	1.8	$	1.2
Tax Fees (2)		0.2		0.5
	$	2.0	$	1.7

_______

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

(2) Tax fees represent amounts we were billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice and tax planning. This category primarily includes services relating to the preparation of unitholder annual K-1 statements.

All services provided by our independent auditor are subject to pre-approval by our audit committee. The Audit Committee is informed of each engagement of the independent auditor to provide services under the policy. The Audit Committee has approved the use of PricewaterhouseCoopers LLP as our independent principal accountant.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)(1) Financial Statements

Our Consolidated Financial Statements are included under Part II, Item 8 of the Annual Report. For a listing of these statements and accompanying footnotes, see “Index to Financial Statements” Page F-1 of this Annual Report.

(a)(2) Financial Statement Schedules

All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financials statements or notes thereto.

(a)(3) Exhibits

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

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

2.3 Purchase and Sale Agreement dated July 27, 2009, by and between Targa Resources Partners LP, Targa GP Inc. and Targa LP Inc. (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 29, 2009 (File No. 001-33303)).

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

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

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

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

3.5 Amendment No. 1, dated May 13, 2008, to the First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 14, 2008 (File No. 001-33303)).

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

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

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4.2 Indenture dated June 18, 2008, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed June 18, 2008 (File No. 001-33303)).

4.3 Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Downstream GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).

4.4 Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Downstream LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).

4.5 Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa LSNG GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).

4.6 Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa LSNG LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.9 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).

4.7	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Sparta LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.11 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
4.8	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Midstream Barge Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.13 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
4.9	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Retail Electric LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.15 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
4.10	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa NGL Pipeline Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.17 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).

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4.11	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Transport LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.19 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
4.12	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Co-Generation LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.21 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
4.13	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Liquids GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.23 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
4.14	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Liquids Marketing and Trade, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.25 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).

4.15 Indenture dated as of July 6, 2009, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 6, 2009 (File No. 001-33303)).

4.16 Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Downstream GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).

4.17 Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Downstream LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).

4.18 Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa LSNG GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.8 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).

4.19 Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa LSNG LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.10 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).

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4.20 Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Sparta LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.12 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).

4.21 Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Midstream Barge Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.14 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).

4.22 Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Retail Electric LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.16 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).

4.23 Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa NGL Pipeline Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.18 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).

4.24 Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Transport LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.20 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).

4.25 Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Co-Generation LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.22 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).

4.26 Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Liquids GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.24 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).

4.27 Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Liquids Marketing and Trade, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.26 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).

4.28 Registration Rights Agreement dated as of July 6, 2009, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 6, 2009 (File No. 001-33303)).

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10.1* Credit Agreement, dated February 14, 2007, by and among Targa Resources Partners LP, as Borrower, Bank of America, N.A., as Administrative Agent, Wachovia Bank, N.A., as Syndication Agent, Merrill Lynch Capital, Royal Bank of Canada and The Royal Bank of Scotland PLC, as Co-Documentation Agents, and the other lenders party thereto.

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

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

10.4 Commitment Increase Supplement, dated June 18, 2008, by and among Targa Resources Partners LP, Bank of America, N.A. and other parties signatory thereto (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed June 24, 2008 (File No. 001-33303)).

10.5 Commitment Increase Supplement, dated July 29, 2009, by and among Targa Resources Partners LP, Bank of America, N.A. and the other parties signatory thereto (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP's Current Report on Form 8-K filed August 4, 2009 (File No. 001-33303).

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

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

10.8 Contribution, Conveyance and Assumption Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa GP Inc., Targa LP Inc., Targa Resources Operating LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (File No. 001-33303)).

10.9 Second Amended and Restated Omnibus Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (file No. 001-33303)).

10.10 Purchase Agreement dated as of June 30, 2009 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and Barclays Capital Inc., as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 6, 2009 (File No. 001-33303)).

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

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

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10.13+ Amendment to Targa Resources Partners LP Long-Term Incentive Plan dated December 18, 2008 (incorporated by reference to Exhibit 10.10 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 27, 2009 (File No. 001-33303)).

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

10.15+* Form of Restricted Unit Grant Agreement - 2010.

10.16+ Form of Performance Unit Grant Agreement – 2007 (incorporated by reference to Exhibit 10.3 to the Partnership’s Current Report on Form 8-K filed with the SEC on February 13, 2007 (File No. 001-33303)).

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

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

10.19+ Form of Performance Unit Grant Agreement – 2010 (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed December 7, 2009 (File No. 001-33303)).

10.20+ Targa Resources Investments Inc. 2008 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.13 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 27, 2009 (File No. 001-33303)).

10.21+ Targa Resources Investments Inc. 2009 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.14 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 27, 2009 (File No. 001-33303)).

10.22+* Targa Resources Investments Inc. 2010 Annual Incentive Compensation Plan.

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

10.24* Amended and Restated Natural Gas Purchase Agreement, effective March 1, 2009, by and between Targa Gas Marketing LLC (Buyer) and Targa North Texas LP (Seller).

10.25 Raw Product Purchase Agreement dated September 24, 2009, to be effective September 1, 2009, between Targa Liquids Marketing and Trade and Targa Permian LP (incorporated by reference to Exhibit 10.3 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (file No. 001-33303)).

10.26 Specification Product Purchase Agreement dated September 24 , 2009, to be effective September 1, 2009, between Targa Liquids Marketing and Trade and Targa Midstream Services Limited Partnership (SE La) (incorporated by reference to Exhibit 10.4 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (file No. 001-33303)).

10.27 Raw Product Purchase Agreement dated September 24 , 2009, to be effective September 1, 2009, between Targa Liquids Marketing and Trade and Targa Midstream Services Limited Partnership (Versado) (incorporated by reference to Exhibit 10.5 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (file No. 001-33303)).

119

10.28 Raw Product Purchase Agreement dated September 24, 2009, to be effective September 1, 2009, between Targa Liquids Marketing and Trade and Targa Midstream Services Limited Partnership (West La) (incorporated by reference to Exhibit 10.6 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (file No. 001-33303)).

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

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

10.31* Amended and Restated Natural Gas Purchase Agreement, effective March 1, 2009, by and between Targa Gas Marketing LLC (Buyer) and Targa Texas Field Services LP (Seller).

10.32* Amendment to the Amended and Restated Natural Gas Purchase Agreement, effective July 1, 2009, by and between Targa Gas Marketing LLC (Buyer) and Targa Texas Field Services LP (Seller).

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

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

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

10.36 Purchase Agreement dated June 12, 2008, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed June 18, 2008 (File No. 001-33303)).

21.1* Subsidiaries of Targa Resources Partners LP.

23.1* Consent of Independent Registered Public Accounting Firm.

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

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

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

120

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

__________

*      Filed herewith

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

+ Management contract or compensatory plan or arrangement.

121

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Targa Resources Partners LP

(Registrant)

By: Targa Resources GP LLC, its general partner

By: /s/ John Robert Sparger

        John Robert Sparger

Senior Vice President and

Chief Accounting Officer

(Principal Accounting Officer)

Date: March 3, 2010

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 3, 2010.

Signature	Title (Position with Targa Resources GP LLC)
/s/ Rene R. Joyce	Chief Executive Officer and Director (Principal Executive Officer)
Rene R. Joyce
/s/ Jeffrey J. McParland	Executive Vice President, Chief Financial Officer and Treasurer
Jeffrey J. McParland	(Principal Financial Officer)
/s/ John Robert Sparger	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)
John Robert Sparger
/s/ James W. Whalen	President —Finance and Administration and Director
James W. Whalen
/s/ Peter R. Kagan	Director
Peter R. Kagan
/s/ Chansoo Joung	Director
Chansoo Joung
/s/ Barry R. Pearl	Director
Barry R. Pearl
/s/ Robert B. Evans	Director
Robert B. Evans
/s/ William D. Sullivan	Director
William D. Sullivan

122

INDEX TO FINANCIAL STATEMENTS
TARGA RESOURCES PARTNERS LP AUDITED CONSOLIDATED FINANCIAL  STATEMENTS
Management's Report on Internal Control Over Financial Reporting	F-2
Report of Independent Registered Public Accounting Firm	F-3
Consolidated Balance Sheets as of December 31, 2009 and 2008	F-4
Consolidated Statements of Operations for the Years Ended December 31, 2009, 2008 and 2007	F-5
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2009, 2008
and 2007	F-6
Consolidated Statement of Changes in Owners' Equity for the Years Ended December 31, 2009, 2008
and 2007	F-7
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007	F-8
Notes to Consolidated Financial Statements	F-9
Note 1—Organization and Operations	F-9
Note 2—Basis of Presentation	F-9
Note 3—Out of Period Adjustment	F-10
Note 4—Significant Accounting Policies	F-10
Note 5—Acquisition of Downstream Business	F-17
Note 6—Inventory	F-18
Note 7—Property, Plant and Equipment	F-18
Note 8—Investment in Unconsolidated Affiliate	F-18
Note 9—Asset Retirement Obligations	F-19
Note 10—Debt Obligations	F-19
Note 11—Partnership Equity and Distributions	F-22
Note 12—Insurance Claims	F-24
Note 13—Accounting for Unit-Based Compensation	F-24
Note 14—Derivative Instruments and Hedging Activities	F-25
Note 15—Related-Party Transactions	F-29
Note 16—Commitments and Contingencies	F-33
Note 17—Fair Value of Financial Instruments	F-34
Note 18—Fair Value Measurements	F-34
Note 19—Segment Information	F-35
Note 20—Other Operating Income	F-39
Note 21—Supplemental Cash Flow Information	F-39
Note 22—Significant Risks and Uncertainties	F-39
Note 23—Selected Quarterly Financial Data (Unaudited)	F-41

F - 1

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Targa Resources GP LLC, the general partner of Targa Resources Partners LP (“the Partnership”), is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

The management of Targa Resources GP LLC has used the framework set forth in the report entitled “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) to evaluate the effectiveness of the Partnership’s internal control over financial reporting. Based on that evaluation, management has concluded that the Partnership’s internal control over financial reporting was effective as of December 31, 2009.

The effectiveness of the Partnership's internal control over financial reporting as of December 31, 2009 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page F-3.

/s/  Rene R. Joyce

Rene R. Joyce

Chief Executive Officer of Targa Resources GP LLC,

 the general partner of Targa Resources Partners LP

 (Principal Executive Officer)

/s/  Jeffrey J. McParland

Jeffrey J. McParland

Executive Vice President and Chief Financial Officer

of Targa Resources GP LLC, the general partner of

Targa Resources Partners LP

(Principal Financial Officer)

F - 2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of Targa Resources Partners LP:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income, of changes in owners’ equity and of cash flows present fairly, in all material respects, the financial position of Targa Resources Partners LP and its subsidiaries (the "Partnership") at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Partnership's internal control over financial reporting based on our audits (which were integrated audits in 2009 and 2008). We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 15 to the consolidated financial statements, the Partnership has engaged in significant transactions with other subsidiaries of its parent company, Targa Resources, Inc., a related-party.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 3, 2010

F - 3

TARGA RESOURCES PARTNERS LP
CONSOLIDATED BALANCE SHEETS
	December 31,
	2009			2008
	(In millions)
ASSETS
Current assets:
Cash and cash equivalents	$	60.4		$	95.3
Trade receivables, net of allowances of $2.2 million		328.3			236.1
Inventory		39.3			72.2
Assets from risk management activities		25.8			91.8
Other current assets		1.2			0.8
Total current assets		455.0			496.2
Property, plant and equipment, at cost		2,096.8			2,036.4
Accumulated depreciation		(418.3	)		(317.3	)
Property, plant and equipment, net		1,678.5			1,719.1
Long-term assets from risk management activities		9.1			68.3
Investment in unconsolidated affiliate		18.5			18.5
Other long-term assets		19.8			12.7
Total assets	$	2,180.9		$	2,314.8
LIABILITIES AND OWNERS' EQUITY
Current liabilities:
Accounts payable to third parties	$	164.0		$	138.7
Accounts payable to affiliates		101.4			17.2
Accrued liabilities		114.2			104.2
Liabilities from risk management activities		16.3			11.7
Total current liabilities		395.9			271.8
Long-term debt payable to third parties		908.4			696.8
Long-term debt payable to Targa Resources, Inc.		-			773.9
Long-term liabilities from risk management activities		28.9			9.7
Deferred income taxes		4.9			3.3
Other long-term liabilities		6.6			6.2
Commitments and contingencies (see Note 16)
Owners' equity:
Common unitholders (61,639,846 and 34,652,000 units issued and
outstanding as of December 31, 2009 and 2008)		850.5			769.9
Subordinated unitholders (0 and 11,528,231 units issued and outstanding
as of December 31, 2009 and 2008)		-			(85.2	)
General partner (1,257,957 and 942,455 units issued and outstanding as of
December 31, 2009 and 2008)		10.1			5.6
Net parent investment		-			(223.5	)
Accumulated other comprehensive income (loss)		(37.8	)		72.2
		822.8			539.0
Noncontrolling interest in subsidiary		13.4			14.1
Total owners' equity		836.2			553.1
Total liabilities and owners' equity	$	2,180.9		$	2,314.8
See notes to consolidated financial statements

F - 4

TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
	Year Ended December 31,
	2009				2008		2007
	(In millions, except per unit amounts)
Revenues from third parties	$	3,897.7		$	7,012.3		$	6,426.3
Revenues from affiliates		197.9			489.8			417.4
Total operating revenues		4,095.6			7,502.1			6,843.7
Costs and expenses:
Product purchases from third parties		2,830.6			5,853.1			5,349.2
Product purchases from affiliates		755.0			1,097.7			952.8
Operating expenses from third parties		158.3			195.2			175.1
Operating expenses from affiliates		26.8			58.8			44.5
Depreciation and amortization expenses		101.2			97.8			93.5
General and administrative expenses		78.9			68.6			64.0
Other		(0.8	)		(0.9	)		(0.3	)
		3,950.0			7,370.3			6,678.8
Income from operations		145.6			131.8			164.9
Other income (expense):
Interest expense from affiliate		(43.4	)		(59.2	)		(58.5	)
Interest expense allocated from Parent		-			-			(19.4	)
Other interest expense, net		(52.0	)		(37.9	)		(21.5	)
Equity in earnings of unconsolidated investment		5.0			3.9			3.5
Gain (loss) on debt repurchases (See Note 10)		(1.5	)		13.1			-
Gain (loss) on mark-to-market derivative instruments		0.8			(1.0	)		(30.2	)
Other		0.7			1.4			(1.1	)
		(90.4	)		(79.7	)		(127.2	)
Income before income taxes		55.2			52.1			37.7
Income tax expense:
Current		(0.2	)		(0.6	)		(0.6	)
Deferred		(0.8	)		(1.8	)		(1.9	)
		(1.0	)		(2.4	)		(2.5	)
Net income		54.2			49.7			35.2
Less: Net income attributable to noncontrolling interest		2.2			0.3			0.1
Net income attributable to Targa Resources Partners LP	$	52.0		$	49.4		$	35.1
Net income (loss) attributable to predecessor operations	$	(2.4	)	$	(42.1	)	$	7.0
Net income attributable to general partner		10.4			7.0			0.6
Net income attributable to limited partners		44.0			84.5			27.5
Net income attributable to Targa Resources Partners LP	$	52.0		$	49.4		$	35.1
Net income per limited partner unit - basic and diluted	$	0.86		$	1.83		$	0.81
Weighted average limited partner units outstanding - basic and
diluted		51.2			46.2			34.0
See notes to consolidated financial statements

F - 5

TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	Year Ended December 31,
	2009			2008			2007
	(In millions)
Net income	$	54.2		$	49.7		$	35.2
Other comprehensive income (loss):
Commodity hedging contracts:
Change in fair value		(72.6	)		129.9			(105.6	)
Reclassification adjustment for settled periods		(45.7	)		33.7			1.0
Related income taxes		-			-			0.3
Interest rate swaps:
Change in fair value		(2.1	)		(19.0	)		(1.7	)
Reclassification adjustment for settled periods		10.4			2.7			(0.2	)
Foreign currency translation adjustment		-			(1.8	)		1.9
Other comprehensive income (loss)		(110.0	)		145.5			(104.3	)
Comprehensive income (loss)		(55.8	)		195.2			(69.1	)
Less: Comprehensive income attributable to
noncontrolling interest		2.2			0.3			0.1
Comprehensive income (loss) attributable to
Targa Resources Partners LP	$	(58.0	)	$	194.9		$	(69.2	)
See notes to consolidated financial statements

F - 6

TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENT OF CHANGES IN OWNERS' EQUITY
										Accumulated
										Other			Net			Non-
	Limited Partners						General			Comprehensive			Parent			controlling
	Common			Subordinated			Partner			Income (Loss)			Investment			Interest			Total
	(In millions)
Balance, December 31, 2006	$	-		$	-		$	-		$	31.3		$	349.2		$	13.4		$	393.9
Contribution from Parent, net		-			-			-			(0.3	)		270.5			-			270.2
Book value of net assets transferred
under common control		-			(83.7	)		(4.1	)		-			(642.0	)		-			(729.8	)
Issuance of units to public (including
underwriter over-allotment), net of
offering and other costs		771.8			-			8.4			-			-			-			780.2
Amortization of equity awards		0.2			-			-			-			-			-			0.2
Distributions to unitholders		(20.9	)		(9.7	)		(0.6	)		-			-			-			(31.2	)
Net income		19.1			8.4			0.6			-			7.0			0.1			35.2
Other comprehensive loss		-			-			-			(104.3	)		-			-			(104.3	)
Balance, December 31, 2007		770.2			(85.0	)		4.3			(73.3	)		(15.3	)		13.5			614.4
Amortization of equity awards		0.3			-			-			-			-			-			0.3
Distributions to unitholders		(64.0	)		(21.3	)		(5.7	)		-			-			-			(91.0	)
Distribution to Parent		-			-			-			-			(166.1	)		-			(166.1	)
Contribution from noncontrolling interest		-			-			-			-			-			0.3			0.3
Net income (loss)		63.4			21.1			7.0			-			(42.1	)		0.3			49.7
Other comprehensive income		-			-			-			145.5			-			-			145.5
Balance, December 31, 2008		769.9			(85.2	)		5.6			72.2			(223.5	)		14.1			553.1
Issuance of common units:
Equity offering		103.1			-			2.2			-			-			-			105.3
Acquisition related		129.8			-			2.7			-			-			-			132.5
Contribution under common control		(7.7	)		-			(0.2	)		-			7.2			-			(0.7	)
Distributions to Parent		-			-			-			-			(68.6	)		(2.6	)		(71.2	)
Settlement of affiliated indebtedness		-			-			-			-			287.3			-			287.3
Distributions to noncontrolling interest		-			-			-			-			-			(0.3	)		(0.3	)
Amortization of equity awards		0.3			-			-			-			-			-			0.3
Other comprehensive loss		-			-			-			(110.0	)		-			-			(110.0	)
Conversion of subordinated units		(97.6	)		97.6			-			-			-			-			-
Net income (loss)		44.5			(0.5	)		10.4			-			(2.4	)		2.2			54.2
Distributions to unitholders		(91.8	)		(11.9	)		(10.6	)		-			-			-			(114.3	)
Balance, December 31, 2009	$	850.5		$	-		$	10.1		$	(37.8	)	$	-		$	13.4		$	836.2
See notes to consolidated financial statements

F - 7

TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Year Ended December 31,
	2009			2008			2007
	(In millions)
Cash flows from operating activities
Net income	$	54.2		$	49.7		$	35.2
Adjustments to reconcile net income to net cash
provided by operating activities:
Amortization in interest expense		3.8			2.1			1.8
Amortization in general and administrative expense		0.3			0.4			0.2
Interest expense on affiliate indebtedness		43.4			59.2			58.5
Depreciation and amortization expense		101.2			97.8			93.5
Accretion of asset retirement obligations		0.4			0.3			0.4
Deferred income tax expense		0.8			1.8			1.9
Equity in earnings of unconsolidated investments, net of distributions		-			0.8			0.4
Risk management activities		37.6			(64.0	)		30.8
Loss (gain) on debt repurchases		1.5			(13.1	)		-
Gain on sale of assets		-			(5.9	)		(0.3	)
Changes in operating assets and liabilities:
Receivables and other assets		(92.5	)		582.8			(117.1	)
Inventory		23.1			75.4			(28.6	)
Accounts payable and other liabilities		126.0			(494.3	)		191.6
Net cash provided by operating activities		299.8			293.0			268.3
Cash flows from investing activities
Outlays for property, plant and equipment		(57.2	)		(86.3	)		(77.6	)
Other, net		0.1			0.2			0.8
Net cash used in investing activities		(57.1	)		(86.1	)		(76.8	)
Cash flows from financing activities
Proceeds from borrowings under credit facility		569.2			185.3			721.3
Repayments of credit facility		(577.7	)		(323.8	)		(95.0	)
Proceeds from issuance of senior notes		237.4			250.0			-
Repurchases of senior notes		(18.9	)		(26.8	)		-
Repayment of affiliated indebtedness		(397.5	)		-			(665.7	)
Proceeds from equity offerings		103.1			-			777.5
Distributions to unitholders		(114.3	)		(91.0	)		(31.2	)
General partner contributions		2.2			-			-
Costs incurred in connection with public offerings		-			(0.1	)		(4.6	)
Costs incurred in connection with financing arrangements		(9.6	)		(7.1	)		(7.5	)
Parent distributions		(71.2	)		(166.1	)		(847.5	)
Loan from Parent		-			3.4			13.0
Contribution from (distributions to) noncontrolling interest		(0.3	)		0.3			-
Net cash used in financing activities		(277.6	)		(175.9	)		(139.7	)
Net change in cash and cash equivalents		(34.9	)		31.0			51.8
Cash and cash equivalents, beginning of year		95.3			64.3			12.5
Cash and cash equivalents, end of year	$	60.4		$	95.3		$	64.3
See notes to consolidated financial statements

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TARGA RESOURCES PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.

Note 1—Organization and Operations

Targa Resources Partners LP, together with its subsidiaries, is a publicly traded Delaware limited partnership formed on October 26, 2006 by Targa Resources, Inc. (“Targa” or “Parent”). In this report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries. References to “TRP LP” are intended to mean and include Targa Resources Partners LP, individually, and not on a consolidated basis. Our common units began trading on the New York Stock Exchange on January 25, 2010 under the symbol “NGLS.” Previously, our common units were listed on The NASDAQ Stock Market LLC under the same symbol. Our business operations consist of natural gas gathering and processing, and the fractionating, storing, terminalling, transporting, distributing and marketing of natural gas liquids (“NGLs”). See Note 19.

Targa Resources GP LLC is a Delaware single-member limited liability company, formed in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly-owned subsidiary of Targa.

On February 14, 2007, we completed an initial public offering (“IPO”) of common units representing limited partner interests in the Partnership. Concurrent with the IPO, Targa conveyed its ownership interests in Targa North Texas GP LLC and Targa North Texas LP (collectively, the “North Texas System”) to us.

On October 24, 2007, Targa conveyed its ownership interests in Targa Texas Field Services LP (the “SAOU System”) and Targa Louisiana Field Services LLC (the “LOU System”) to us. This conveyance consisted of the SAOU System’s natural gas gathering and processing businesses and the LOU System’s natural gas gathering and processing businesses.

On September 24, 2009, we acquired Targa’s interests in Targa Downstream LP, Targa LSNG LP, Targa Downstream GP LLC and Targa LSNG GP LLC (collectively, the “Downstream Business”) in a transaction among entities under common control. See Note 5.

Note 2—Basis of Presentation

These consolidated financial statements include our accounts and: (i) prior to September 24, 2009 the assets, liabilities and operations of the Downstream Business; (ii) prior to October 24, 2007 the assets, liabilities and operations of the SAOU and LOU Systems as the predecessor entities; and (iii) prior to February 14, 2007 the assets, liabilities and operations of the North Texas System. The effect on reported equity of including such prior results of these acquired businesses is reported as net parent investment in our consolidated balance sheets and consolidated statement of changes in owners’ equity.

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

Our consolidated financial statements and all other financial information included in this report have been retrospectively adjusted to assume that the acquisition of the Downstream Business from Targa by us had occurred at the date when both the Downstream Business and the North Texas System met the accounting requirements for entities under common control (October31, 2005) following the acquisition of the SAOU and LOU Systems. As a

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result, financial statements and financial information presented for prior periods in this report have been retrospectively adjusted.

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). We refer to the operations, assets and liabilities of the North Texas System, the SAOU and LOU Systems, and the Downstream Business, prior to our acquisition from Targa, collectively as our “predecessors.” The consolidated financial statements of our predecessors have been prepared from the separate records maintained by Targa and may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessors had been operated as unaffiliated entities. All significant intercompany balances and transactions have been eliminated. Transactions among us and other Targa operations have been identified in the consolidated financial statements as transactions among affiliates.

We have been allocated certain general and administrative expenses incurred by our Parent in order to present financial statements on a stand-alone basis. See Note 15. All of the allocations are not necessarily indicative of the costs and expenses that would have resulted had we been operated as stand-alone entities.

In preparing the accompanying consolidated financial statements, the Partnership has reviewed, as determined necessary by the Partnership, events that have occurred after December 31, 2009, up until the issuance of the financial statements. See Notes 11 and 16.

Note 3—Out of Period Adjustment

During 2009, we recorded an adjustment related to prior periods which increased our revenue, income before income taxes and net income for 2009 by $1.8 million. The adjustment related to natural gas sales transactions which occurred during 2006. After evaluating the quantitative and qualitative aspects of the error, we concluded that our previously issued financial statements were not materially misstated and the effect of recognizing the adjustment in the 2009 financial statements was not material to our results of operations, financial position or cash flows.

Note 4—Significant Accounting Policies

Asset retirement obligations (“AROs”). AROs are legal obligations associated with the retirement of tangible long-lived assets that result from the asset’s acquisition, construction, development and/or normal operation. An ARO is initially measured at its estimated fair value. Upon initial recognition of an ARO, we record an increase to the carrying amount of the related long-lived asset and an offsetting ARO liability. The consolidated cost of the asset and the capitalized asset retirement obligation is depreciated using the straight-line method over the period during which the long-lived asset is expected to provide benefits. After the initial period of ARO recognition, the ARO will change as a result of either the passage of time or revisions to the original estimates of either the amounts of estimated cash flows or their timing.

Changes due to the passage of time increase the carrying amount of the liability because there are fewer periods remaining from the initial measurement date until the settlement date; therefore, the present values of the discounted future settlement amount increases. These changes are recorded as a period cost called accretion expense. Changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows shall be recognized as an increase or a decrease in the carrying amount of the liability for an asset retirement obligation and the related asset retirement cost capitalized as part of the carrying amount of the related long-lived asset.Upon settlement, AROs will be extinguished by us at either the recorded amount or we will recognize a gain or loss on the difference between the recorded amount and the actual settlement cost. See Note 9.

Cash and Cash Equivalents. Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value. As of December 31, 2009 and 2008, accrued liabilities included approximately $5.3 million and $3.6 million of outstanding checks that were reclassified from cash and cash equivalents.

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 Comprehensive Income. Comprehensive income includes net income and other comprehensive income (“OCI”), which includes unrealized gains and losses on derivative instruments that are designated as hedges, and currency translation adjustments.

Concentration of Credit Risk. Financial instruments which potentially subject us to concentrations of credit risk consist primarily of trade accounts receivable and commodity derivative instruments.

Trade Accounts Receivable. We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and terms, letters of credit, and rights of offset. We also use prepayments and guarantees to limit credit risk to ensure that our established credit criteria are met.

Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the level of established reserves, we make judgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to an allowance for doubtful accounts may be required.

The following table presents the activity of our allowance for doubtful accounts for the periods indicated:

	Year Ended December 31,
	2009		2008		2007
Balance at beginning of year	$	2.2	$	0.9	$	0.8
Additions		-		1.3		0.2
Deductions		-		-		(0.1	)
Balance at end of year	$	2.2	$	2.2	$	0.9

Significant Commercial Relationships. The following table lists the percentage of our consolidated sales or purchases with customers and suppliers which accounted for more than 10% of our consolidated revenues and consolidated product purchases for the periods indicated:

	Year Ended December 31,
	2009		2008		2007
% of consolidated revenues
Chevron Phillips Chemical Company LLC		17%		20%		22%
% of consolidated product purchases
Louis Dreyfus Energy Services L.P.		12%		9%		7%

Consolidation Policy. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest.

We follow the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the operating and financial policies of the investee.

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

Environmental Liabilities. 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. See Note 16.

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Gas Processing Imbalances. Quantities of natural gas and/or NGLs over-delivered or under-delivered related to certain gas plant operational balancing agreements are recorded monthly as inventory or as a payable using weighted average prices as of the time the imbalance was created. Monthly, inventory imbalances receivable are valued at the lower of cost or market; inventory imbalances payable are valued at replacement cost. These imbalances are settled either by current cash-out settlements or by adjusting future receipts or deliveries of natural gas or NGLs.

Income Taxes. Our earnings or losses for federal income tax purposes are included in the tax returns of our individual partners. As such, we are not subject to federal income taxes.

In May 2006, Texas adopted a margin tax, consisting generally of a 1% tax on the amount by which total revenues exceed cost of goods sold, as apportioned to Texas. Accordingly, we have estimated our liability for this tax and it is recorded as a tax liability.

   Inventory. Our product inventories consist primarily of NGLs. Most product inventories turn over monthly, but some inventory, primarily propane, is acquired and held during the year to meet anticipated heating season requirements of our customers. Product inventories are valued at the lower of cost or market using the average cost method.

Net Income per Limited Partner Unit. Net income attributable to Targa Resources Partners LP is allocated to the general partner and the limited partners (common unitholders) in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner. Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income by the weighted average number of outstanding limited partner units during the period.

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are classified as participating securities and are included in our computation of basic and diluted net income per limited partner unit.

We compute earnings per unit using the two-class method. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit using the two-class method. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the general partner, even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit.

The calculation of basic and diluted net income per common unit are the same for all periods presented as distributable cash flow was greater than net income for those periods.

 Noncontrolling Interest. Noncontrolling interest represents third party ownership in the net assets of our consolidated subsidiary, Cedar Bayou Fractionators. For financial reporting purposes, the assets and liabilities of our majority owned subsidiary are consolidated with any third party investor’s interest shown as noncontrolling interest. In the statements of operations, noncontrolling interest reflects the allocation of joint venture earnings to a third party investor. Distributions to and contributions from noncontrolling interest represent cash payments and cash contributions from such third party investor.

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Price Risk Management (Hedging). We have designated certain downstream liquids marketing contracts that meet the definition of a derivative as normal purchases and normal sales, which are not accounted for as derivatives. All derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the balance sheets at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If a derivative qualifies for hedge accounting and is designated as a cash flow hedge, the effective portion of the unrealized gain or loss on the derivative is deferred in accumulated OCI, a component of owner’s equity, and reclassified to earnings when the forecasted transaction occurs. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged.

Our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. Hedge ineffectiveness is measured on a quarterly basis. Any ineffective portion of the unrealized gain or loss is reclassified to earnings in the current period.

The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge accounting is discontinued prospectively when a hedge instrument is terminated or ceases to be highly effective. Gains and losses deferred in OCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is no longer probable that a hedged forecasted transaction will occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately. See Notes 14, 15 and 18.

Product Exchanges. Exchanges of NGL products are executed to satisfy timing and logistical needs of the exchanging parties. Volumes received and delivered under exchange agreements are recorded as inventory. If the locations of receipt and delivery are in different markets, a price differential may be billed or owed. The price differential is recorded as either accounts receivable or accrued liabilities.

Property, Plant and Equipment. Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. The estimated service lives of our functional asset groups are as follows:

Asset Group	Range of Years
Gas gathering systems and processing systems	5 to 20
Fractionation, terminalling and natural gas liquids storage facilities	5 to 25
Transportation assets	10 to 25
Other property and equipment	3 to 25

Expenditures for maintenance and repairs are expensed as incurred. Expenditures to refurbish assets that extend the useful lives or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset or major asset component.

Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs.

We capitalize certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs. Upon disposition or retirement of property, plant and equipment, any gain or loss is charged to operations.

We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying

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amount of the assets. Asset recoverability is measured 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;

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

· NGL fractionation, terminalling and storage, transportation and treating.

We recognize revenues when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, if applicable, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectibility is reasonably assured.

For processing services, we receive either fees or a percentage of commodities as payment for these services, depending on the type of contract. Under percent-of-proceeds contracts, we receive either an agreed upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs or an agreed upon percentage based on index related prices for the natural gas and NGLs. Percent-of-value and percent-of-liquids contracts are variations on this arrangement. Under keep-whole contracts, we keep the NGLs extracted and return the processed natural gas or value of the natural gas to the producer. Natural gas or NGLs that we receive for services or purchase for resale are in turn sold and recognized in accordance with the criteria outlined above. Under fee-based contracts, we receive a fee based on throughput volumes.

We generally report revenues gross in our consolidated statements of operations. Except for fee-based contracts, we act as the principal in the transactions where we receive commodities, take title to the natural gas and NGLs, and incur the risks and rewards of ownership.

During 2009, we reclassified NGL marketing fractionation and other service fees to revenues that were originally recorded in product purchase costs. The reclassification increased revenues and product purchases for 2008 and 2007 by $28.7 million and $27.6 million. This reclassification had no impact on our income from operations, net income, financial position or cash flows and we concluded that our previously issued financial statements were not materially misstated.

Unit-Based Employee Compensation. We award share-based compensation to non-management directors in the form of restricted common units, which are deemed to be equity awards. Compensation expense on restricted common units is measured by the fair value of the award at the date of grant. Compensation expense is recognized in general and administrative expense over the requisite service period of each award. See Note 13.

 Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the period. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues and operating and

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general and administrative costs (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the useful lives of assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results could differ materially from estimated amounts.

Accounting Pronouncements Recently Adopted

Financial Accounting Standards Board (“FASB”) Codification

In June 2009, FASB issued the FASB Accounting Standards Codification (the “Codification” or “ASC”) as the source of authoritative GAAP recognized by FASB to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission (“SEC”) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The Codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009. As of the effective date, the Codification supersedes all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification has become non-authoritative.

Following the Codification, FASB will no longer issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, it will issue Accounting Standards Updates (“ASUs”). FASB will not consider ASUs as authoritative in their own right. They will serve only to update the Codification, provide background information about the guidance, and provide the basis for conclusions on changes in the Codification.

Fair Value Measurements

In September 2006, FASB issued guidance regarding fair value measurement that defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. This guidance applies to previous accounting guidance that require or permit fair value measurements, and accordingly, does not require any new fair value measurements. The guidance was initially effective as of January 1, 2008, but in February 2008, FASB delayed the effective date for applying the guidance to nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis, until periods beginning after November 15, 2008. We adopted the guidance as of January 1, 2008 with respect to financial assets and liabilities within its scope and the impact was not material to our financial statements. As of January 1, 2009, nonfinancial assets and nonfinancial liabilities were also required to be measured at fair value. The adoption of these additional provisions did not have a material impact on our financial statements. See Note 18.

In April 2009, FASB issued guidance for determining fair values when there is no active market or where the price inputs being used represent distressed sales. Specifically, it reaffirms the need to use judgment to ascertain if a formerly active market has become inactive and in determining fair values when markets have become inactive. We adopted the guidance as of June 30, 2009. There have been no material financial statement implications relating to our adoption.

In April 2009, FASB issued guidance that requires disclosures of fair value for any financial instruments not currently reflected at fair value on the balance sheets for all interim periods. We adopted these provisions as of June 30, 2009. There have been no material financial statement implications relating to this adoption. See Note 17.

In January 2010, FASB issued guidance that requires additional disclosures about fair value measurements including transfers in and out of Levels 1 and 2 and a higher level of disaggregation for the different types of financial instruments. For the reconciliation of Level 3 fair value measurements, information about purchases, sales, issuances and settlements should be presented separately. This guidance is effective for annual and interim reporting periods beginning after December 15, 2009 for most of the new disclosures and for periods beginning after December 15, 2010 for the new Level 3 disclosures. Comparative disclosures are not required in the first year the disclosures are required. Our adoption did not have a material impact on our consolidated financial statements.

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Business Combinations

In December 2007, FASB issued guidance that requires the acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction, establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed and requires the acquirer to disclose certain information related to the nature and financial effect of the business combination. It also establishes principles and requirements for how an acquirer recognizes any noncontrolling interest in the acquiree and the goodwill acquired in a business combination. This guidance was effective on a prospective basis for business combinations for which the acquisition date is on or after January 1, 2009. For any business combination that takes place subsequent to January 1, 2009, this guidance may have a material impact on our financial statements. The nature and extent of any such impact will depend upon the terms and conditions of the transaction. This guidance did not apply to our acquisition of the Downstream Business as it is a transfer of net assets between entities under common control.

In April 2009, FASB issued guidance that amends and clarifies application issues on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This update is effective for assets and liabilities arising from contingencies in business combinations for which the acquisition date is on or after January 1, 2009. There have been no material financial statement implications relating to the adoption of this update.

Other

In December 2007, FASB issued guidance that  requires all entities to report noncontrolling interests in subsidiaries as a separate component of equity in the consolidated statement of financial position, to clearly identify consolidated net income attributable to the parent and to the noncontrolling interest on the face of the consolidated statement of income, and to provide sufficient disclosure that clearly identifies and distinguishes between the interest of the parent and the interests of noncontrolling owners. It also establishes accounting and reporting standards for changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. We adopted these amended provisions effective January 1, 2009, which required retrospective reclassification of our consolidated financial statements for all periods presented in this filing. As a result of adoption, we have reclassified our noncontrolling interest (formerly minority interest) on our consolidated balance sheets, from a component of liabilities to a component of equity and have also reclassified net income attributable to noncontrolling interest on our consolidated statements of operations, to below net income for all periods presented. Furthermore, we have displayed the portion of other comprehensive income that is attributable to the noncontrolling interest within our consolidated statements of comprehensive income.

In March 2008, the FASB’s Emerging Issues Task Force (“EITF”) issued guidance as to how a master limited partnership (“MLP”) should allocate and present earnings per unit using the two-class method when the MLP’s partnership agreement contains incentive distribution rights. Under the two-class method, current period earnings are allocated to the partners according to the distribution formula for available cash set forth in the MLP’s partnership agreement. Our adoption of this guidance on January 1, 2009, did not impact our consolidated financial position, results of operations or cash flows, or our basic and diluted net income per unit.

In June 2008, FASB issued guidance that requires us to retrospectively adjust our earnings per unit data that result in us recognizing unvested unit-based payment awards as participating units in our basic earnings per unit calculation. Our adoption of this guidance on adopted January 1, 2009 did not have a material impact on our computation of basic can diluted net income per unit.

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In May 2009, FASB issued guidance that establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. This guidance sets forth (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements, and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. It is effective for interim and annual periods ended after June 15, 2009 and should be applied prospectively. Our adoption did not have a material impact on our financial statements.

In June 2009, the SEC Staff issued guidance that amends or rescinds portions of the SEC staff’s interpretive guidance included in the Staff Accounting Bulletin Series in order to make the relevant interpretive guidance consistent with the ASC. Our adoption did not have a material impact on our consolidated financial statements.

In December 2009, the FASB amended consolidation guidance for variable interest entities (“VIEs”). VIEs are entities whose equity investors do not have sufficient equity capital at risk such that the entity cannot finance its own activities. When a business has a controlling financial interest in a VIE, the assets, liabilities and profit or loss of that entity must be included in consolidation. A business enterprise must consolidate a VIE when that enterprise has a variable interest that will cover most of the entity’s expected losses and/or receive most of the entity’s anticipated residual return. The new guidance, among other things, eliminates the scope exception for qualifying special-purpose entities, amends certain guidance for determining whether an entity is a VIE, expands the list of events that trigger reconsideration of whether an entity is a VIE, requires a qualitative rather than a quantitative analysis to determine the primary beneficiary of a VIE, requires continuous assessments of whether a company is the primary beneficiary of a VIE and requires enhanced disclosures about a company’s involvement with a VIE. This guidance is effective for us on January 1, 2010 and early adoption is prohibited. At December 31, 2009, we had not identified any interests which qualified as VIEs and our adoption of this new guidance is not expected to have a material impact on our financial statements.

Note 5—Acquisition of Downstream Business

On September 24, 2009, we acquired Targa’s interests in the Downstream Business for $530 million. Consideration to Targa comprised $397.5 million in cash and the issuance to Targa of 174,033 general partner units and 8,527,615 common units. The form of the transaction reflected in our consolidated financial statements was:

·   Targa contributed the Downstream Business to us.

-   Prior to the contribution, the Downstream Business’ affiliate indebtedness payable to Targa totaled $817.3 million, inclusive of $223.0 million of accrued interest.

-   Immediately prior to, and in contemplation of, the contribution, $287.3 million of the Downstream Business’ affiliated indebtedness was settled through a separate capital contribution from Targa.

-   On the contribution date, the Downstream Business’ affiliate indebtedness payable to Targa was $530 million.

·   We repaid the affiliate indebtedness with: (i) $397.5 million in cash; (ii) 174,033 in general partner units with an agreed-upon value of $2.7 million; and (iii) 8,527,615 in common units with an agreed-upon value of $129.8 million.

Our acquisition of the Downstream Business has been accounted for as a transfer of net assets between entities under common control.

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

We now operate in two divisions: (i) Natural Gas Gathering and Processing (also a segment) and (ii) NGL Logistics and Marketing. Our NGL Logistics and Marketing division consists of three segments: (a) Logistics Assets, (b) NGL Distribution and Marketing and (c) Wholesale Marketing. As a result of the acquisition of the Downstream Business, we are now reporting segment information. See Note 19.

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Note 6—Inventory

Due to fluctuating commodity prices for natural gas liquids, we occasionally recognize lower of cost or market adjustments when the carrying values of our inventories exceeds their net realizable value. These non-cash adjustments are charged to product purchases within operating costs and expenses in the period they are recognized, with the related cash impact in the subsequent period. For 2009, we did not recognize an adjustment to the carrying value of our NGL inventory. As of December 31, 2008 and 2007, we recognized $6.0 million and $0.2 million to reduce the carrying value of NGL inventory to its net realizable value.

Note 7—Property, Plant and Equipment

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

	December 31,
	2009			2008
Natural gas gathering systems	$	1,225.6		$	1,187.1
Processing and fractionation facilities		404.4			374.0
Terminalling and natural gas liquids storage facilities		238.5			221.9
Transportation assets		150.7			144.5
Other property and equipment		16.8			14.9
Land		49.8			49.8
Construction in progress		11.0			44.2
		2,096.8			2,036.4
Accumulated depreciation		(418.3	)		(317.3	)
	$	1,678.5		$	1,719.1

Note 8—Investment in Unconsolidated Affiliate

As of December 31, 2009 and 2008, our unconsolidated investment consisted of a 38.75% ownership interest in Gulf Coast Fractionators LP (“GCF”), a venture that fractionates natural gas liquids on the Gulf Coast. As of December 31, 2009 and 2008, our investment in GCF was $18.5 million.

Our equity in the net assets of GCF exceeded our acquisition date investment account by approximately $5.2 million. This amount is being amortized over the estimated useful life of the net assets (25 years) on a straight-line basis, and is included as a component of our equity in earnings of unconsolidated investments.

The following table shows our equity earnings and cash distributions with respect to our unconsolidated investment in GCF for the years indicated:

	Year Ended December 31,
	2009		2008		2007
Equity in earnings	$	5.0	$	3.9	$	3.5
Cash distributions		5.0		4.7		3.9

Pursuant to the Purchase and Sales Agreement of the Downstream Business acquisition, Targa is entitled to receive cumulative distributions made after September 23, 2009 of up to $4.6 million. As of December 31, 2009, Targa was still entitled to $2.3 million of GCF future distributions.

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Note 9—Asset Retirement Obligations

Our asset retirement obligations are included in our consolidated balance sheets as a component of other long-term liabilities. The changes in our aggregate asset retirement obligations are as follows:

	Year Ended December 31,
	2009		2008			2007
Beginning of period	$	6.2	$	5.9		$	5.4
Liabilities settled		-		(0.2	)		-
Change in cash flow estimate		-		0.2			0.1
Accretion expense		0.4		0.3			0.4
End of period	$	6.6	$	6.2		$	5.9

Note 10—Debt Obligations

Consolidated debt obligations consisted of the following as of the dates indicated:

	December 31,
	2009		2008
Targa Resources Partners LP:
Senior secured revolving credit facility, variable rate, due February 2012	$	479.2	$	487.7
Senior unsecured notes, 8¼% fixed rate, due July 2016		209.1		209.1
Senior unsecured notes, 11¼% fixed rate, due July 2017 (1)		220.1		-
Targa Downstream LP:
Note payable to Parent, 10% fixed rate, due December 2011 (including accrued interest of $0 and $175,343)		-		744.0
Targa LSNG LP:
Note payable to Parent, 10% fixed rate, due December 2011 (including accrued interest of $0 and $4,281)		-		29.9
Total long-term debt	$	908.4	$	1,470.7
Letters of credit outstanding under senior secured revolving credit facility	$	69.2	$	9.7

_______

(1) The carrying amount of the notes includes $11.2 million of unamortized original issue discount as of December 31, 2009.

Information Regarding Variable Interest Rates Paid

The following table shows the range of interest rates paid and weighted average interest rate paid on our variable-rate debt obligations during 2009:

	Range of interest rates paid	Weighted average interest rate paid
Senior secured revolving credit facility	1.2% to 4.5%		1.7%

Affiliated Indebtedness

The contributions of the North Texas System and the Downstream Business have been treated as transfers between entities under common control (see Note 2) and periods prior to the dates of the transfers have been adjusted to present comparative information. On January 1, 2007, Targa contributed to us affiliated indebtedness related to the North Texas System of $904.5 million (including accrued interest of $88.3 million computed at 10%

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per annum) and affiliated indebtedness related to the Downstream Business of $639.7 million (including accrued interest of $61.8 million). We recorded $9.8 million in interest expense associated with this affiliated debt for the period from January 1, 2007 through February 13, 2007 associated with the North Texas System. During 2009, 2008 and 2007, we recorded $43.4 million, $59.2 million and $58.5 million in affiliated interest expense related to the affiliated indebtedness associated with the Downstream Business.

In connection with the contribution of the North Texas System in 2007, all affiliated debt and accrued interest was settled. In connection with the acquisition of the Downstream Business in September 2009, we settled all of the remaining obligations, including accrued interest, under our affiliated debt agreement. See Note 5. At December 31, 2009 we had no affiliated indebtedness outstanding.

Credit Agreement

On February 14, 2007, we entered into a credit agreement which provided for a five-year $500 million credit facility with a syndicate of financial institutions. On October 24, 2007, we entered into the First Amendment to Credit Agreement which allows us to request commitments under the credit agreement, as supplemented and amended, up to $1 billion. We currently have $977.5 million committed under the senior secured credit facility. In October 2008, Lehman Bank defaulted on a borrowing request under our senior secured credit facility. Lehman’s commitment under the facility is $19 million and is currently unfunded which effectively reduces our total commitments under our credit facility by $19 million.

The credit facility bears interest at our option, at the higher of the lender’s prime rate or the federal funds rate plus 0.5%, plus an applicable margin ranging from 0% to 1.25% dependent on our total leverage ratio, or LIBOR plus an applicable margin ranging from 1.0% to 2.25% dependent on our total leverage ratio. Our credit facility is secured by substantially all of our assets. As of December 31, 2009, we had approximately $479.2 million of borrowings outstanding under our senior secured credit facility and approximately $69.2 million of outstanding letters of credit.

Our senior secured credit facility restricts our ability to make distributions of available cash to unitholders if a default or an event of default (as defined in our senior secured credit agreement) has occurred and is continuing. The senior secured credit facility requires us to maintain a leverage ratio (the ratio of consolidated indebtedness to our consolidated EBITDA, as defined in the senior secured credit agreement of less than or equal to 5.50 to 1.00 and a senior secured indebtedness ratio (the ratio of senior secured indebtedness to consolidated EBITDA, as defined in the senior secured credit agreement) of less than or equal to 4.50 to 1.00, each subject to certain adjustments. The senior secured credit facility also requires us to maintain an interest coverage ratio (the ratio of our consolidated EBITDA to our consolidated interest expense, as defined in the senior secured credit agreement) of greater than or equal to 2.25 to 1.00 determined as of the last day of each quarter for the four-fiscal quarter period ending on the date of determination, as well as upon the occurrence of certain events, including the incurrence of additional permitted indebtedness. In conjunction with a material acquisition, we have the option to increase the leverage ratio to 6.00 to 1.00 and to increase the senior secured indebtedness ratio to 5.00 to 1.00 for a period of up to a year.

The credit facility matures on February 14, 2012, at which time all unpaid principal and interest is due.

8¼% Senior Notes due 2016

On June 18, 2008, we completed the private placement under Rule 144A and Regulation S of the Securities Act of 1933 of $250 million in aggregate principal amount of 8¼% senior notes due 2016 (the “8¼% Notes”). The 8¼% Notes:

· are our unsecured senior obligations;

· rank pari passu in 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

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· are unconditionally guaranteed by us.

The 8¼% 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 8¼% Notes accrues at the rate of 8¼% per annum and is payable semi-annually in arrears on January 1 and July 1, commencing on January 1, 2009.

At any time prior to July 1, 2011, we may redeem up to 35% of the aggregate principal amount of the 8¼% 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 8¼% Notes (excluding 8¼% Notes held by us) remains outstanding immediately after the occurrence of such redemption; and

(2) the redemption occurs within 90 days of the date of the closing of such equity offering.

At any time prior to July 1, 2012, we may also redeem all or a part of the 8¼% Notes at a redemption price equal to 100% of the principal amount of the 8¼% 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 8¼% 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 8¼% Notes redeemed, if redeemed during the twelve-month period beginning on July 1 of each year indicated below:

Year	Percentage
2012		104.125%
2013		102.063%
2014 and thereafter		100.000%

During 2008, we repurchased $40.9 million face value of our outstanding 8¼% Notes in open market transactions at an aggregate purchase price of $28.3 million, including $1.5 million of accrued interest. We recognized a gain on the debt repurchases of $13.1 million associated with the purchased notes. The repurchased 8¼% Notes were retired and are not eligible for re-issue at a later date.

11¼% Senior Notes due 2017

On July 6, 2009, we completed the private placement under Rule 144A and Regulation S of the Securities Act of 1933 of $250 million in aggregate principal amount of 11¼% senior notes due 2017 (the “11¼% Notes”). The 11¼% Notes were issued at 94.973% of the face amount, resulting in gross proceeds of $237.4 million. The 11¼% Notes:

· are our unsecured senior obligations;

· rank pari passu in right of payment with our existing and future senior indebtedness, including

indebtedness under our senior secured revolving credit facility;

· are senior in right of payment to any of our future subordinated indebtedness; and

· are unconditionally guaranteed by us.

The 11¼% Notes are effectively subordinated to all indebtedness under our credit agreement, which is secured by substantially all of our assets, to the extent of the value of the collateral securing that indebtedness.

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Interest on the 11¼% Notes accrues at the rate of 11¼% per annum and is payable semi-annually in arrears on January 15 and July 15, commencing on January 15, 2010.

At any time prior to July 15, 2012, we may redeem up to 35% of the aggregate principal amount of the 11¼% Notes with the net cash proceeds of certain equity offerings by us at a redemption price of 111.25% of the principal amount, plus accrued and unpaid interest to the redemption date, provided that:

(1)  at least 65% of the aggregate principal amount of the 11¼% Notes (excluding 11¼% Notes held by us) remains outstanding immediately after the occurrence of such redemption; and

(2)  the redemption occurs within 90 days of the date of the closing of such equity offering.

At any time prior to July 15, 2013, we may also redeem all or a part of the 11¼% Notes at a redemption price equal to 100% of the principal amount of the 11¼% Notes redeemed plus the applicable premium as defined in the indenture as of, and accrued and unpaid interest to, the date of redemption.

On or after July 15, 2013, we may redeem all or a part of the 11¼% Notes at the redemption prices set forth below (expressed as percentages of principal amount) plus accrued and unpaid interest on the 11¼% Notes redeemed, if redeemed during the twelve-month period beginning on July 15 of each year indicated below:

Year	Percentage
2013		105.625%
2014		102.813%
2015 and thereafter		100.000%

The 11¼% Notes are subject to a registration rights agreement dated as of July 6, 2009. Under the registration rights agreement, we are required to file by July 7, 2010 a registration statement with respect to any 11¼% Notes that are not freely transferable without volume restrictions by holders of the 11¼% Notes that are not affiliates of ours. If we fail to do so, additional interest will accrue on the principal amount of the 11¼% Notes. We have determined that the payment of additional interest is not probable. As a result, we have not recorded a liability for any contingent obligation. Any subsequent accruals of a liability or payments made under this registration rights agreement will be charged to earnings as interest expense in the period they are recognized or paid.

During 2009, we repurchased $18.7 million face value of our outstanding 11¼% Notes in open market transactions at an aggregated purchase price of $18.9 million plus accrued interest of $0.3 million. We recognized a loss on the debt repurchases of $1.5 million, including $0.4 million in debt issue costs associated with the repurchased notes. The repurchased 11¼% Notes were retired and are not eligible for re-issue at a later date.

Compliance with Debt Covenants

As of December 31, 2009, the Partnership was in compliance with the covenants contained in our various debt agreements.

Note 11—Partnership Equity and Distributions

General. In accordance with the Partnership Agreement, we must distribute all of our available cash to unitholders of record on the applicable record date, as determined by the general partner within 45 days after the end of each quarter.

Conversion of Subordinated Units. Under the terms of our amended and restated Partnership Agreement, all 11,528,231 subordinated units converted to common units on a one-for-one basis on May 19, 2009. The conversion had no impact upon our calculation of earnings per unit since the subordinated units were included in the basic and diluted earnings per unit calculation.

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Public Offering of Common Units. On August 12, 2009, we completed a unit offering under our shelf registration statement of 6,900,000 common units representing limited partner interests in us at a price of $15.70 per common unit. Net proceeds of the offering were $105.3 million, after deducting underwriting discounts, commissions and offering expenses, and including the general partner’s proportionate capital contribution of $2.2 million. We used a portion of the proceeds to repay $103.5 million of outstanding borrowings under our senior secured revolving credit facility.

Distributions will generally be made 98% to the common unitholders and 2% to the general partner, subject to the payment of incentive distributions to the extent that certain target levels of cash distributions are achieved.

Under the quarterly incentive distribution provisions, generally our general partner is entitled to 13% of amounts distributed in excess of $0.3881 per unit, 23% of the amounts distributed in excess of $0.4219 per unit and 48% of amounts distributed in excess of $0.50625 per unit. No incentive distributions were paid to us as part of our general partner interest prior to the fourth quarter of 2007. To the extent there is sufficient available cash, the holders of common units are entitled to receive the minimum quarterly distribution of $0.3375 per unit, plus arrearages.

The following table shows the amount of cash distributions we paid to date:

		Distributions Paid										Distributions
	For the Three	Limited Partners				General Partner						per limited
Date Paid	Months Ended	Common		Subordinated		Incentive			2%	Total		partner unit
		(In millions, except per unit amounts)
2009
November 14, 2009	September 30, 2009	$	31.9	$	-	$	2.6	$	0.7	$	35.2	$	0.5175
August 14, 2009	June 30, 2009		23.9		-		2.0		0.5		26.4		0.5175
May 15, 2009	March 31, 2009		18.0		5.9		1.9		0.5		26.3		0.5175
February 13, 2009	December 31, 2008		18.0		6.0		1.9		0.5		26.4		0.5175
2008
November 14, 2008	September 30, 2008	$	17.9	$	6.0	$	1.9	$	0.5	$	26.3	$	0.5175
August 14, 2008	June 30, 2008		17.8		5.9		1.7		0.5		25.9		0.5125
May 15, 2008	March 31, 2008		14.5		4.8		0.2		0.4		19.9		0.4175
February 14, 2008	December 31, 2007		13.8		4.6		0.1		0.4		18.9		0.3975

Subsequent Events. On January 19, 2010, we completed a public offering of 5,500,000 common units representing limited partner interests in the Partnership (“common units”) under our existing shelf registration statement on Form S-3 at a price of $23.14 per common unit ($22.17 per common unit, net of underwriting discounts), providing net proceeds of $121.9 million. Pursuant to the exercise of the underwriters’ overallotment option, we sold an additional 825,000 common units at $23.14 per common unit, providing net proceeds of $18.3 million. We used the net proceeds from the offering for general partnership purposes, which included reducing borrowings under our senior secured credit facility.

On February 12, 2010, we paid a cash distribution of $0.5175 per unit on our outstanding common units to unitholders of record on February 3, 2010, for the three months ended December 31, 2009. The total distribution paid was $38.8 million, with $24.8 million paid to our non-affiliated common unitholders and $10.4 million, $0.8 million and $2.8 million paid to Targa for its common unit ownership, general partner interest and incentive distribution rights.

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Note 12—Insurance Claims

We recognize income from business interruption insurance in our consolidated statements of operations as a component of revenues from third parties in the period that a proof of loss is executed and submitted to the insurers for payment. For 2009, income from business interruption insurance resulting from the effects of Hurricane Ike was $1.9 million. In addition, we received $0.5 million during 2009 as a result of fire damage at a third-party plant related to our wholesale marketing segment. For 2008 and 2007, income from business interruption insurance resulting from the effects of Hurricanes Katrina and Rita was $18.1 million and $6.4 million. In addition, we received $0.6 million during 2008 as a result of fire damage at a third-party plant related to our wholesale marketing segment.

Hurricanes Gustav and Ike

Certain of our Louisiana and Texas facilities sustained damage and had disruptions to their operations during the 2008 hurricane season from two Gulf Coast hurricanes—Gustav and Ike. As of December 31, 2008, we recorded a $4.8 million loss provision (net of estimated insurance reimbursements) related to the hurricanes. During 2009, the estimate was reduced by $0.8 million. During 2009, expenditures related to the hurricanes included $6.9 million for previously accrued repair costs and $0.3 million capitalized as improvements.

Under Common Control accounting, the effects of insurance claims on predecessor operations have been included in our restated financial statements, however, as part of the Downstream acquisition, Targa retained the right to receive any future insurance proceeds from claims associated with Gustav and Ike.

Note 13—Accounting for Unit-Based Compensation

In 2007, the parent of Targa, Targa Resources Investments Inc. (“Targa Investments”), adopted a Long-Term Incentive Plan (“LTIP”) for employees, consultants and directors of us and our affiliates who perform services for Targa Investments or its affiliates. The LTIP provides for the grant of cash-settled performance units, which are linked to the performance of our common units and may include distribution equivalent rights (“DERs”). The LTIP is administered by the compensation committee of the board of directors of Targa Investments. Subject to applicable vesting criteria, a DER entitles the grantee to a cash payment equal to cash distributions paid on an outstanding common unit.

Grants outstanding under Targa Investments’ LTIP were 275,400 under the 2007 program, 135,800 under the 2008 program, 534,900 units under the 2009 program and 90,403 units under the 2010 program. During 2009, there were forfeitures under the LTIP of 12,025 units. Grants under the 2007, 2008, 2009 and 2010 programs are payable in August 2010, July 2011, June 2012 and June 2013. Each vested performance unit will entitle the grantee to a cash payment equal to the then value of a Partnership common unit, including DERs. Vesting of performance units is based on the total return per our common unit through the end of the performance period, relative to the total return of a defined peer group.

Because the performance units require cash settlement, they have been accounted for as liabilities by Targa. The fair value of a performance unit is the sum of: (i) the closing price of one of our common units on the reporting date; (ii) the fair value of an at-the-money call option on a performance unit with a grant date equal to the reporting date and an expiration date equal to the last day of the performance period; and (iii) estimated DERs. The fair value of the call options was estimated using a Black-Scholes option pricing model with a dividend yield of 8.5%, and with risk-free rates and volatilities of 0.3% and 42% under the 2007 program, 0.8% and 61% under the 2008 program, 1.4% and 61% under the 2009 program and 1.4% and 52% under the 2010 program.

At December 31, 2009, the aggregate fair value of performance units expected to vest was $23.5 million. The remaining recognition period for the unrecognized compensation cost is approximately three and a half years. During 2009, 2008 and 2007 Targa recognized compensation expense of $10.5 million, $0.1 million and $2.7 million related to the performance units. Based on Targa’s allocation methodology, we recognized allocated general and administrative expenses related to the performance units of $6.6 million, $0.1 million and $1.9 million for 2009, 2008 and 2007.

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 During 2009 and 2008, Targa Resources GP LLC, the general partner of the Partnership, also made equity-based awards of 32,000 and 16,000 restricted common units of the Partnership (4,000 and 2,000 restricted common units of the Partnership to each of the Partnership’s and Targa Investments’ non-management directors) under its (“Incentive Plan”). The awards will settle with the delivery of common units and are subject to three-year vesting, without a performance condition, and will vest ratably on each anniversary of the grant date. During 2009 and 2008, we recognized compensation expense of $0.3 million related to these awards. We estimate that the remaining fair value of $0.2 million will be recognized in expense over approximately two years. As of December 31, 2009 there were 41,993 unvested restricted common units outstanding under this plan.

The following table summarizes our unit-based awards for each of the periods indicated (in units and dollars):

	Year Ended December 31, 2009
Outstanding at beginning of period		26,664
Granted		32,000
Vested		(16,671	)
Outstanding at end of period		41,993
Weighted average grant date fair value per share	$	12.88

Subsequent Event. On January 22, 2010, TRGP made equity-based awards of 2,250 restricted common units (15,750 total restricted common units) of the Partnership to each of ours and Targa Investments’ non-management directors under the Incentive Plan. The awards will settle with the delivery of common units and are subject to three year vesting, without a performance condition, and will vest ratably on each anniversary of the grant date.

Note 14—Derivative Instruments and Hedging Activities

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas and NGLs, as well as changes in interest rates.

Commodity Price Risk. A majority of the revenues from our natural gas gathering and processing business are derived from percent-of-proceeds contracts under which we receive a portion of the natural gas and/or NGLs or equity volumes, as payment for services. The prices of natural gas and NGLs are subject to market fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into commodity derivative transactions designed to mitigate the impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged.

The primary purpose of our commodity risk management activities is to hedge our exposure to commodity price risk and reduce fluctuations in our operating cash flow despite fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of December 31, 2009, we have hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the years 2010 through 2013 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of our expected equity volumes that are hedged decrease over time. With swaps, we typically receive an agreed upon fixed price for a specified notional quantity of natural gas or NGL and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) to hedge additional expected equity commodity volumes without creating volumetric risk. Our commodity hedges may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if market prices decline below the prices at which these hedges are set. If market prices rise

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above the prices at which we have hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges.

We have tailored our hedges to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. Our NGL hedges cover baskets of ethane, propane, normal butane, iso-butane and natural gasoline based upon our expected equity NGL composition. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Additionally, our NGL hedges are based on published index prices for delivery at Mont Belvieu and our natural gas hedges are based on published index prices for delivery at Columbia Gulf, Houston Ship Channel, Mid-Continent and Waha, which closely approximate our actual NGL and natural gas delivery points. We hedge a portion of our condensate sales using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude.

At December 31, 2009, the notional volumes of our commodity hedges were:

Commodity		Instrument	Unit	2010		2011		2012		2013
Natural Gas	Swaps		MMBtu/d		16,494		14,000		10,000		4,000
NGL	Swaps		Bbl/d		5,607		4,000		2,700		-
NGL	Floors		Bbl/d		-		199		231		-
Condensate	Swaps		Bbl/d		501		350		200		200

Interest Rate Risk. We are exposed to changes in interest rates, primarily as a result of our variable rate borrowings under our credit facility. To the extent that interest rates increase, our interest expense for our revolving debt will also increase. As of December 31, 2009, we had borrowings of approximately $479.2 million outstanding under our revolving credit facility. In an effort to reduce the variability of our cash flows, we have entered into several interest rate swap and interest rate basis swap agreements. Under these agreements, which are accounted for as cash flow hedges, the base interest rate on the specified notional amount of our variable rate debt is effectively fixed for the term of each agreement and ineffectiveness is required to be measured each reporting period. The fair values of the interest rate swap agreements, which are adjusted regularly, have been aggregated by counterparty for classification in our consolidated balance sheets. Accordingly, unrealized gains and losses relating to the interest rate swaps are recorded in OCI until the interest expense on the related debt is recognized in earnings.

Credit Risk. Our credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value to us at the reporting date. At such times, these outstanding instruments expose us to credit loss in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of our counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted.

As of December 31, 2009, affiliates of Goldman Sachs and Bank of America (“BofA”) accounted for 93% and 5% of our counterparty credit exposure related to commodity derivative instruments. Goldman Sachs and BofA are major financial institutions, each possessing investment grade credit ratings based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services.

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The following schedules reflect the fair values of derivative instruments in our financial statements:

	Asset Derivatives					Liability Derivatives
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2009		2008		Location	2009		2008
Derivatives designated as hedging instruments
Commodity contracts	Current assets	$	24.5	$	88.2	Current liabilities	$	7.8	$	-
	Long term assets		7.0		68.3	Long term liabilities		24.2		0.1
Interest rate contracts	Current assets		0.2		-	Current liabilities		8.0		8.0
	Long term assets		1.9		-	Long term liabilities		4.7		9.6
Total derivatives designated
as hedging instruments			33.6		156.5			44.7		17.7
Derivatives not designated as hedging instruments
Commodity contracts	Current assets		1.1		3.6	Current liabilities		0.5		3.7
	Long term assets		0.2		-	Long term liabilities		-		-
Total derivatives not designated
as hedging instruments			1.3		3.6			0.5		3.7
Total derivatives		$	34.9	$	160.1		$	45.2	$	21.4

The fair value of derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. These contracts may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which we have hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges.

Our earnings are also affected by the use of the mark-to-market method of accounting for derivative financial instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheets and through earnings (i.e., using the “mark-to-market” method) rather than being deferred until the anticipated transaction affects earnings. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. During 2009, 2008 and 2007, we recorded mark-to-market gains (losses) of $0.8 million, ($1.0) million and ($30.2) million.

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The following tables reflect amounts reclassified from OCI to revenue and expense:

	Amount of Gain (Loss) Reclassified from OCI to Income
Location of Gain (Loss)	(Effective Portion)
Reclassified from	Year Ended December 31,
OCI into Income	2009			2008			2007
Interest expense, net	$	(10.4	)	$	(2.7	)	$	0.2
Revenues		45.8			(33.7	)		(1.0	)
	$	35.4		$	(36.4	)	$	(0.8	)

	Amount of Gain (Loss) Recognized in Income on Derivatives
Location of Gain (Loss)	(Ineffective Portion)
Reclassified from	Year Ended December 31,
OCI into Income	2009			2008		2007
Interest expense, net	$	-		$	-	$	-
Revenues		(0.1	)		-		-
	$	(0.1	)	$	-	$	-

	Amount of Gain (Loss)
	Recognized in OCI on
Derivatives in	Derivatives (Effective Portion)
Cash Flow Hedging	Year Ended December 31,
Relationships	2009			2008			2007
Interest rate contracts	$	(2.1	)	$	(19.0	)	$	(1.7	)
Commodity contracts		(72.6	)		129.9			(105.6	)
	$	(74.7	)	$	110.9		$	(107.3	)

		Amount of Gain (Loss) Recognized
Derivatives	Location of Gain (Loss)	in Income on Derivatives
Not Designated as	Recognized in Income	Year Ended December 31,
Hedging Instruments	on Derivatives	2009		2008			2007
Commodity contracts	Other income (expense)	$	0.8	$	(1.0	)	$	(30.2	)

As of December 31, 2009, OCI included $28.7 million of unrealized net losses on commodity hedges. As of December 31, 2008 and 2007, OCI included $89.6 million and $74.0 million of unrealized net gains on commodity hedges. Hedge ineffectiveness of $0.1 million was recorded in 2009. There were no adjustments for hedge ineffectiveness for 2008 or 2007.

As of December 31, 2009, 2008 and 2007, OCI also included $9.3 million, $17.5 million and $1.2 million of unrealized losses on interest rate hedges. There were no adjustments for hedge ineffectiveness for 2009, 2008 or 2007.

As of December 31, 2009, deferred net gains (losses) of $31.5 million on commodity hedges and ($7.8) million on interest rate hedges recorded in OCI are expected to be reclassified to expense during the next twelve months.

In May 2008 we entered into certain NGL derivative contracts with Lehman Brothers Commodity Services Inc., a subsidiary of Lehman Brothers Holdings Inc. (“Lehman”). Due to Lehman’s bankruptcy filing, it is unlikely that we will receive full or partial payment of any amounts that may become owed to us under these contracts. Accordingly, we discontinued hedge accounting treatment for these contracts in July 2008. Deferred losses of

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$0.1 million and $0.3 million will be reclassified from OCI to revenues during 2011 and 2012 when the forecasted transactions related to these contracts are expected to occur. During 2008, we recognized a non-cash mark-to-market loss on derivatives of $1.0 million to adjust the fair value of the Lehman derivative contracts to zero. In October 2008, we terminated the Lehman derivative contracts.

In July 2008, we paid $87.4 million to terminate certain out-of-the-money natural gas and NGL commodity swaps. Prior to the terminations, these swaps were designated as hedges. Deferred losses of $27.9 million will be reclassified from OCI as a non-cash reduction of revenue during 2010 when the hedged forecasted sales transactions occur. During 2009 and 2008, deferred losses of $38.8 million and $20.8 million related to the terminated swaps were reclassified from OCI as a non-cash reduction to revenue. We also entered into new natural gas and NGL commodity swaps at then current market prices that match the production volumes of the terminated swaps through 2010.

Interest Rate Swaps

As of December 31, 2009, we had $479.2 million outstanding under our credit facility, with interest accruing at a base rate plus an applicable margin. In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates we have entered into interest rate swaps and interest rate basis swaps that effectively fix the base rate on $300 million in borrowings as shown below:

Period	Fixed Rate		Notional Amount	Fair Value
2010		3.67%	$300 million	$	(7.8	)
2011		3.52%	300 million		(5.1	)
2012		3.40%	300 million		(0.6	)
2013		3.39%	300 million		1.6
01/01 - 4/24/2014		3.39%	300 million		1.3
				$	(10.6	)

All interest rate swaps and interest rate basis swaps have been designated as cash flow hedges of variable rate interest payments on borrowings under our credit facility.

The fair value of derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices and interest rates based on those observed in underlying markets. These contracts may expose us to the risk of financial loss in certain circumstances.

See Notes 4, 15 and 18 for additional disclosures related to derivative instruments and hedging activities.

Note 15—Related-Party Transactions

Targa Resources, Inc.

On February 14, 2007, we entered into an Omnibus Agreement with Targa, our general partner and others that addressed the reimbursement of our general partner for costs incurred on our behalf and indemnification matters. Any or all of the provisions of this agreement, other than the indemnification provisions described in Note 16, are terminable by Targa at its option if our general partner is removed without cause and units held by our general partner and its affiliates are not voted in favor of that removal. The Omnibus Agreement will terminate in the event of a change of control of us or our general partner.

Concurrent with the closing of the acquisition of the SAOU and LOU Systems and the Downstream Business, we amended and restated our Omnibus Agreement (as amended and restated) with Targa, our general partner and others that addresses the reimbursement of our general partner for costs incurred on our behalf, competition and indemnification matters.

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As part of the Downstream Business transaction, Targa is providing distribution support to us in the form of a reduction in the reimbursement for general and administrative expense allocated to us if necessary for a 1.0 times distribution coverage ratio, at the current $0.5175 per limited partner unit, subject to maximum support of $8.0 million in any quarter. The distribution support is in effect for the nine-quarter period beginning with the fourth quarter of 2009 and continuing through the fourth quarter of 2011. No distribution support was required for the fourth quarter of 2009.

Reimbursement of Operating and General and Administrative Expense

Under the Omnibus Agreement, we reimburse Targa for the payment of certain operating expenses, including compensation and benefits of operating personnel, and for the provision of various general and administrative services for our benefit. With respect to the North Texas System, we reimburse Targa for the following expenses:

· general and administrative expenses, which were capped at $5.0 million annually for three years through February 14, 2010, subject to increases based on increases in the Consumer Price Index and subject to further increases in connection with expansions of our operations through the acquisition or construction of new assets or businesses with the concurrence of our conflicts committee; thereafter, our general partner will determine the general and administrative expenses to be allocated to us in accordance with our partnership agreement; and

· operations and certain direct general and administrative expenses, which are not subject to the $5.0 million cap for general and administrative expenses.

With respect to the SAOU System, the LOU System and the Downstream Business, we will reimburse Targa for the following expenses:

· general and administrative expenses, which are not capped, allocated to the SAOU System, the LOU System and the Downstream Business according to Targa’s allocation practice; and

· operating and certain direct expenses, which are not capped.

Pursuant to these arrangements, Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. We reimburse Targa for the direct expenses to provide these services as well as other direct expenses it incurs on our behalf, such as compensation of operational personnel performing services for our benefit and the cost of their employee benefits, including 401(k), pension and health insurance benefits.

Allocations

Allocation of costs. The employees supporting our operations are employees of Targa. Our financial statements include costs allocated to us by Targa for centralized general and administrative services performed by Targa, as well as depreciation of assets utilized by Targa’s centralized general and administrative functions. Costs allocated to us were based on identification of Targa’s resources which directly benefit us and our proportionate share of costs based on our estimated usage of shared resources and functions. All of the allocations are based on assumptions that management believes are reasonable; however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if we had been operated as a stand-alone entity. Prior to the initial IPO and the subsequent acquisition of the SAOU and LOU Systems these allocations were not settled in cash, but were settled through an adjustment to partners’ capital accounts. Effective February 14, 2007, all of the North Texas System’s allocations were settled monthly in cash. Effective October 23, 2007, all of the SAOU and LOU Systems’ allocations were settled monthly in cash.

Allocations of long-term debt, debt issue costs, interest rate swaps and interest expense. Prior to January 1, 2007, our financial statements included long-term debt, debt issue costs, interest rate swaps and interest expense allocated from Targa. The allocations were calculated in a manner similar to Targa’s purchase price allocation related to its acquisition of the SAOU and LOU Systems and the Downstream Business, and were based on the fair

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value of acquired tangible assets plus related net working capital and unconsolidated equity interests. These allocations were not settled in cash. Settlement of these allocations occurred through adjustments to partners’ capital. The allocated debt, debt issue costs and interest rate swaps for the North Texas System and the Downstream Business, were settled through deemed partner contributions of $846.3 million and $478.7 million on January 1, 2007. On October 23, 2007, The allocated debt, debt issue costs and interest rate swaps related to the SAOU and LOU Systems were settled through a deemed partner contribution of $179.6 million.

Contracts with Affiliates

Sales to and purchases from affiliates. We routinely conduct business with other subsidiaries of Targa. The related-party transactions result primarily from purchases and sales of natural gas and purchases of NGL products. Prior to February 14, 2007, all of our expenditures were paid through Targa, resulting in intercompany transactions. Prior to February 14, 2007, settlement of these intercompany transactions was through adjustments to partners’ capital accounts. After the conveyance of the assets of the North Texas System, the SAOU and LOU Systems, and the Downstream Business, all intercompany transactions were settled in cash.

Natural Gas Purchase Agreements. During 2007, the North Texas, SAOU and LOU Systems entered into natural gas purchase agreements at a price based on Targa Gas Marketing LLC’s (“TGM”) sale price for such natural gas, less TGM’s costs and expenses associated therewith. These agreements have an initial term of 15 years and automatically extend for a term of five years, unless the agreements are otherwise terminated by either party. Furthermore, either party may elect to terminate the agreements if either party ceases to be an affiliate of Targa. In addition, Targa manages the SAOU and LOU Systems’ natural gas sales to third parties under contracts that remain in the name of the Targa Texas Field Services and Targa Louisiana Field Services.

NGL Product Purchase Agreements. On September 24, 2009, Targa Liquids Marketing and Trade, a Delaware general partnership and indirectly, wholly-owned subsidiary of the Partnership (“Targa Liquids”), entered into product purchase agreements with Targa Midstream Services Limited Partnership, a Delaware limited partnership and indirectly wholly-owned subsidiary of Targa (“TMSLP”), and Targa Permian LP, a Delaware limited partnership and indirectly, wholly-owned subsidiary of Targa (“Targa Permian”), pursuant to which Targa Liquids will purchase all volumes of NGLs that are owned or controlled by TMSLP and Targa Permian and not otherwise committed for sale to a third party, at a price based on the prevailing market price less transportation, fractionation and certain other fees. The product purchase agreements will have an initial term of 15 years and will automatically extend for a term of five years. Furthermore, either party may elect to terminate the agreement if either party ceases to be an affiliate of Targa. Each product purchase agreement is effective as of September 1, 2009.

The following table summarizes the sales to and purchases from affiliates of Targa, payments made or received by Targa on behalf of us and allocations of costs from Targa which were settled through adjustments to partners’ capital prior to the contribution of the North Texas System and the Downstream Business by Targa and the acquisition of the SAOU and LOU Systems from Targa. Management believes these transactions are executed on terms that are fair and reasonable.

	Year Ended December 31,
	2009			2008			2007
Sales to affiliates	$	197.9		$	489.8		$	417.4
Purchases from affiliates:
Included in product purchases		755.0			1,097.7			952.8
Included in operating expenses		26.8			58.8			44.5
Payments made to our Parent		(1,255.9	)		(1,658.2	)		(911.6	)
Parent allocation of interest expense		-			-			19.4
Parent allocation of general and administrative expense		63.9			61.2			60.4
Net change in affiliate payable		84.2			48.4			23.5
Unit distributions to Targa		132.5			-			-
Cash distributions to Targa		32.9			27.0			10.4
Settlement of affiliated indebtedness		287.3			-			-

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Centralized Cash Management

Prior to the conveyance of the assets of the North Texas, SAOU and LOU Systems and the Downstream Business to us, the excess cash from these subsidiaries was held in separate bank accounts and swept to a centralized account under Targa. Beginning with the contribution of these systems to us, their bank accounts have been maintained under a separate centralized cash management system applicable to our business operations.

For the North Texas System, prior to February 14, 2007, cash distributions are deemed to have occurred through partners’ capital and are reflected as an adjustment to partners’ capital. For the period from January 1, 2007 through February 13, 2007, deemed net capital distributions from us were $0.5 million. For the SAOU and LOU Systems for the period from January 1, 2007 through October 23, 2007, deemed net capital distributions from us were $133.6 million. For the Downstream Business for the period from January 1, 2007 through September 23, 2009, net capital distributions of cash to (from) Targa were $71.2 million, $166.1 million and $(26.0) million for 2009, 2008 and 2007.

Transactions with GCF

For the years 2009, 2008 and 2007, transactions with GCF which were included in revenues totaled $0.2 million, $0.5 million and $4.5 million. For the same periods, transactions included in costs and expenses were $1.4 million, $3.5 million and $3.3 million. These transactions were at market prices consistent with similar transactions with nonaffiliated entities.

Relationships with Warburg Pincus LLC

Chansoo Joung and Peter Kagan, two of the directors of Targa, are Managing Directors of Warburg Pincus LLC and are also directors of Broad Oak Energy, Inc. (“Broad Oak”) from whom we buy natural gas and NGL products. Affiliates of Warburg Pincus LLC own a controlling interest in Broad Oak. We purchased $9.7 million and $4.8 million of product from Broad Oak during 2009 and 2008. These transactions were at market prices consistent with similar transactions with nonaffiliated entities.

Relationships with Bank of America

Equity

An affiliate of BofA is an equity investor in Targa Investments, which indirectly owns our general partner.

Financial Services

 BofA is a lender and an administrative agent under our senior secured credit facility.

Hedging Arrangements

We have entered into various commodity derivative transactions with BofA. The following table shows our open commodity derivatives with BofA as of December 31, 2009:

Period	Commodity	Daily Volumes			Average Price			Index
Jan 2010 - Dec 2010	Natural Gas		3,289	MMBtu	$	7.39	per MMBtu	IF-WAHA
Jan 2010 - Jun 2010	Natural Gas		663	MMBtu		8.16	per MMBtu	NY-HH
Jan 2010 - Dec 2010	Condensate		181	Bbl		69.28	per Bbl	NY-WTI

As of December 31, 2009, the fair value of these open positions was an asset of $0.9 million. During 2009, 2008 and 2007, we received from (paid to) BofA $25.4 million, ($9.1) million and ($1.9) million in commodity derivative settlements.

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Commercial Relationships

We have executed NGL sales and purchase transactions on the spot market with BofA. For the years 2009, 2008 and 2007, sales to BofA which were included in revenues totaled $0.5 million, $4.4 million and $18.1 million. For the same periods, purchases from BofA were $0.3 million, $0.8 million and $9.4 million.

Note 16—Commitments and Contingencies

Certain property and equipment is leased under non-cancelable leases that require fixed monthly rental payments and expire at various dates through 2099. Transportation contracts require us to make payments for capacity and expire at various dates through 2013. Surface and underground access for gathering, processing, and distribution assets that are located on property not owned by us is obtained through right-of-way agreements, which require annual rental payments and expire at various dates through 2099. Future non-cancelable commitments related to certain contractual obligations are presented below:

	Payments Due by Period
	Total		2010		2011		2012		2013		2014		Thereafter
Operating lease obligations (1)	$	38.0	$	8.9	$	6.5	$	6.2	$	3.3	$	2.6	$	10.5
Capacity payments (2)		2.7		2.0		0.7		-		-		-		-
Right-of-way		11.4		0.9		0.8		0.8		0.7		0.5		7.7
	$	52.1	$	11.8	$	8.0	$	7.0	$	4.0	$	3.1	$	18.2

_______

(1) Include minimum lease payment obligations associated with gas processing plant site leases and railcar leases.

(2) Consist of capacity payments for firm transportation contracts.

Total expenses related to operating leases, right-of-way and capacity payments were $10.7 million, $1.1 million, and $3.4 million for 2009, $11.3 million, $2.2 million and $3.1 million for 2008, and $13.1 million, $1.4 million and $2.9 million for 2007.

Environmental

Under the Omnibus Agreement described in Note 15, Targa indemnified us for three years from February 14, 2007 against certain potential environmental claims, losses and expenses associated with the operation of the North Texas System occurring before such date that were not reserved on the books of the North Texas System. Targa’s maximum liability for this indemnification obligation will not exceed $10.0 million and Targa will not have any obligation under this indemnification until our aggregate losses exceed $250,000. We have indemnified Targa against environmental liabilities related to the North Texas System arising or occurring after February 14, 2007.

Our environmental liabilities not covered by the Omnibus Agreement are for ground water assessment and remediation and such reserves were less than $0.1 million as of December 31, 2008.

Legal Proceedings

We are a party to various legal proceedings and/or regulatory proceedings and certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against us. We believe all such matters are without merit or involve amounts which, if resolved unfavorably, would not have a material effect on our financial position, results of operations, or cash flows, except for the items more fully described below.

On December 8, 2005, WTG Gas Processing (“WTG”) filed suit in the 333rd District Court of Harris County, Texas against several defendants, including Targa Resources, Inc. and three other Targa entities and private equity funds affiliated with Warburg Pincus LLC, seeking damages from the defendants. The suit alleges that Targa and private equity funds affiliated with Warburg Pincus, along with ConocoPhillips Company (“ConocoPhillips”) and Morgan Stanley, tortiously interfered with (i) a contract WTG claims to have had to purchase the SAOU System from ConocoPhillips and (ii) prospective business relations of WTG. WTG claims the alleged interference resulted from Targa’s competition to purchase the ConocoPhillips’ assets and its successful acquisition of those assets in

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2004. On October 2, 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s claims. WTG’s motion to reconsider and for a new trial was overruled. On January 2, 2008, WTG filed a notice of appeal. On February 3, 2009, the parties presented oral arguments to the 14th Court of Appeals in Houston Texas.

Subsequent event. On February 23, 2010, the 14th Court of Appeals affirmed the District Court’s final judgment in favor of defendants in its entirety. Targa has agreed to indemnify us for any claim or liability arising out of the WTG suit.

Note 17—Fair Value of Financial Instruments

The estimated fair values of our assets and liabilities classified as financial instruments have been determined using available market information and valuation methodologies described below. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying values of items comprising current assets and current liabilities approximate fair values due to the short term maturities of these instruments. Derivative financial instruments included in our financial statements are stated at fair value.

The carrying value of the senior secured revolving credit facility approximates its fair value, as its interest rate is based on prevailing market rates. The fair value of the senior unsecured notes is based on quoted market prices based on trades of such debt. The carrying value of the notes payable to Parent at December 31, 2008 approximates their fair value as they were settled at their stated amount on September 24, 2009. The carrying amounts and fair values of our other financial instruments are as follows as of the dates indicated:

	As of December 31,
	2009				2008
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
Senior unsecured notes, 8¼% fixed rate	$	209.1	$	206.5	$	209.1	$	128.3
Senior unsecured notes, 11¼% fixed rate (1)		220.1		253.5		-		-
Notes payable to Parent:
Targa Downstream LP		-		-		744.0		744.0
Targa LSNG LP		-		-		29.9		29.9

_______

(1) The carrying amount of the 11¼% Notes includes $11.2 million of unamortized original issue discount as of December 31, 2009.

Note 18—Fair Value Measurements

We account for the fair value of our financial assets and liabilities using a three-tier fair value hierarchy, which prioritizes the significant inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

Our derivative instruments consist of financially settled commodity and interest rate swap and option contracts and fixed price commodity contracts with certain customers. We determine the value of our derivative contracts utilizing a discounted cash flow model for swaps and a standard option pricing model for options, based on inputs that are readily available in public markets. We have consistently applied these valuation techniques in all periods presented and believe we have obtained the most accurate information available for the types of derivative contracts we hold. We have categorized the inputs for these contracts as Level 2 or Level 3.

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The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2009 and 2008. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.

As of December 31, 2009	Total		Level 1		Level 2		Level 3
Assets from commodity derivative contracts	$	31.5	$	-	$	31.5	$	-
Assets from interest rate derivatives		2.1		-		2.1		-
Total assets	$	33.6	$	-	$	33.6	$	-
Liabilities from commodity derivative contracts	$	32.0	$	-	$	21.9	$	10.1
Liabilities from interest rate derivatives		12.7		-		12.7		-
Total liabilities	$	44.7	$	-	$	34.6	$	10.1

As of December 31, 2008	Total		Level 1		Level 2		Level 3
Assets from commodity derivative contracts	$	160.1	$	-	$	36.8	$	123.3
Assets from interest rate derivatives		-		-		-		-
Total assets	$	160.1	$	-	$	36.8	$	123.3
Liabilities from commodity derivative contracts	$	3.9	$	-	$	3.9	$	-
Liabilities from interest rate derivatives		17.5		-		17.5		-
Total liabilities	$	21.4	$	-	$	21.4	$	-

The following table sets forth a reconciliation of the changes in the fair value of our financial instruments classified as Level 3 in the fair value hierarchy:

	Commodity Derivative Contracts
	2009			2008
Balance, December 31, 2008	$	123.3		$	(71.4	)
Unrealized gains (losses) included in OCI		(37.7	)		99.1
Purchases		-			2.9
Terminations		-			77.8
Settlements		(31.4	)		14.9
Transfers out of Level 3 (1)		(64.3	)		-
Balance, December 31, 2009	$	(10.1	)	$	123.3

_______

(1) During 2009, we reclassified certain of our NGL derivative contracts from Level 3 (unobservable inputs in which little or no market data exist) to Level 2 as we were able to obtain directly observable inputs other than quoted prices in active markets.

Note 19—Segment Information

We categorize the midstream natural gas industry into, and describe our business in, two divisions: (i) Natural Gas Gathering and Processing (also a segment) and (ii) NGL Logistics and Marketing. Our NGL Logistics and Marketing division consists of three segments: (a) Logistics Assets, (b) NGL Distribution and Marketing and (c) Wholesale Marketing.

The Natural Gas Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting

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natural gas liquids and removing impurities. These assets are located in North Texas, Louisiana and the Permian Basin of West Texas.

The Logistics Assets segment is involved with gathering and storing mixed NGLs and fractionating, storing, and transporting of finished NGLs. These assets are generally connected to and supplied, in part, by our Natural Gas Gathering and Processing segment and are predominantly located in Mont Belvieu, Texas and Western Louisiana.

The NGL Distribution and Marketing segment markets our own natural gas liquids production and purchased natural gas liquids products in selected United States markets. We also had the right to purchase or market substantially all of Chevron’s natural gas liquids pursuant to a Master Natural Gas Liquids Purchase Agreement.

The Wholesale Marketing segment includes our refinery services business and wholesale propane marketing operations. In our refinery services business, we provide liquefied petroleum gas balancing services, purchase natural gas liquids products from refinery customers and sell natural gas liquids products to various customers. Our wholesale propane marketing operations include the sale of propane and related logistics services to multi-state retailers, independent retailers and other end users. Wholesale Marketing operates principally in the United States, and has a small marketing presence in Canada.

Eliminations and Other includes amounts related to general and administrative expenses not allocated to segment operations, corporate development, interest expense, income tax expense, and the depreciation and cost of equipment used in our headquarters office. Eliminations and Other also includes the elimination of intersegment revenues and expenses.

Our reportable segment information is shown in the following tables:

	Year Ended December 31, 2009
	Natural Gas Gathering and Processing			Logistics Assets		NGL Distribution and Marketing		Wholesale Marketing		Eliminations and Other			Total
Revenues from third parties	$	448.9		$	118.6	$	2,522.2	$	808.0	$	-		$	3,897.7
Revenues from affiliates		197.0			0.2		-		0.7		-			197.9
Intersegment revenues		430.6			95.5		414.0		77.3		(1,017.4	)		-
Revenues		1,076.5			214.3		2,936.2		886.0		(1,017.4	)		4,095.6
Product purchases from third parties		655.3			-		1,721.1		454.2		-			2,830.6
Product purchases from affiliates		169.3			-		585.7		-		-			755.0
Intersegment product purchases		32.1			-		583.3		408.1		(1,023.5	)		-
Product purchases		856.7			-		2,890.1		862.3		(1,023.5	)		3,585.6
Operating expenses		51.4			106.6		0.3		-		-			158.3
Operating expenses from affiliates		-			20.7		-		-		6.1			26.8
Operating expenses		51.4			127.3		0.3		-		6.1			185.1
Operating margin	$	168.4		$	87.0	$	45.8	$	23.7	$	-		$	324.9
Other financial information:
Equity in earnings of   unconsolidated investment	$	-		$	5.0	$	-	$	-	$	-		$	5.0
Identifiable assets		1,284.5			494.0		214.2		117.9		70.3			2,180.9
Unconsolidated investments		-			18.5		-		-		-			18.5
Capital expenditures		28.8			22.0		9.8		-		-			60.6
Revenues by type:
Commodity Sales	$	1,065.6		$	0.1	$	2,907.9	$	884.5	$	(919.8	)	$	3,938.3
Services		11.1			212.3		28.3		1.0		(97.6	)		155.1
Other		(0.2	)		1.9		-		0.5		-			2.2
	$	1,076.5		$	214.3	$	2,936.2	$	886.0	$	(1,017.4	)	$	4,095.6

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	Year Ended December 31, 2008
	Natural Gas Gathering and Processing		Logistics Assets			NGL Distribution and Marketing		Wholesale Marketing		Eliminations and Other			Total
Revenues from third parties	$	848.7	$	106.0		$	4,642.1	$	1,415.5	$	-		$	7,012.3
Revenues from affiliates		489.1		-			-		0.7		-			489.8
Intersegment revenues		736.3		132.0			571.3		43.9		(1,483.5	)		-
Revenues		2,074.1		238.0			5,213.4		1,460.1		(1,483.5	)		7,502.1
Product purchases from third parties		1,479.0		(0.1	)		3,474.0		900.2		-			5,853.1
Product purchases from affiliates		286.9		-			808.6		2.2		-			1,097.7
Intersegment product purchases		37.1		0.1			910.6		544.5		(1,492.3	)		-
Product purchases		1,803.0		-			5,193.2		1,446.9		(1,492.3	)		6,950.8
Operating expenses from third parties		55.3		138.1			1.7		0.1		-			195.2
Operating expenses from affiliates		-		50.0			-		-		8.8			58.8
Operating expenses		55.3		188.1			1.7		0.1		8.8			254.0
Operating margin	$	215.8	$	49.9		$	18.5	$	13.1	$	-		$	297.3
Other financial information:
Equity in earnings of   unconsolidated investment	$	-	$	3.9		$	-	$	-	$	-		$	3.9
Identifiable assets		1,580.9		498.2			142.3		115.7		(22.3	)		2,314.8
Unconsolidated investments		-		18.5			-		-		-			18.5
Capital expenditures		59.0		41.5			-		-		-			100.5
Revenues by type:
Commodity sales	$	2,063.7	$	-		$	5,172.2	$	1,453.2	$	(1,349.3	)	$	7,339.8
Services		10.4		235.4			31.6		0.4		(134.1	)		143.7
Other		-		2.6			9.6		6.5		(0.1	)		18.6
	$	2,074.1	$	238.0		$	5,213.4	$	1,460.1	$	(1,483.5	)	$	7,502.1

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	Year Ended December 31, 2007
	Natural Gas Gathering and Processing		Logistics Assets		NGL Distribution and Marketing			Wholesale Marketing		Eliminations and Other			Total
Revenues from third parties	$	630.8	$	83.1	$	4,447.2		$	1,265.2	$	-		$	6,426.3
Revenues from affiliates		420.0		-		(3.3	)		0.7		-			417.4
Intersegment revenues		610.7		112.0		479.5			30.1		(1,232.3	)		-
Revenues		1,661.5		195.1		4,923.4			1,296.0		(1,232.3	)		6,843.7
Product purchases from third parties		1,215.7		-		3,350.1			783.4		-			5,349.2
Product purchases from affiliates		188.5		-		764.1			0.2		-			952.8
Intersegment product purchases		2.6		-		752.2			489.5		(1,244.3	)		-
Product purchases		1,406.8		-		4,866.4			1,273.1		(1,244.3	)		6,302.0
Operating expenses from third parties		50.9		122.6		1.5			0.1		-			175.1
Operating expenses from affiliates		-		32.5		-			-		12.0			44.5
Operating expenses		50.9		155.1		1.5			0.1		12.0			219.6
Operating margin	$	203.8	$	40.0	$	55.5		$	22.8	$	-		$	322.1
Other financial information:
Equity in earnings of   unconsolidated investment	$	-	$	3.5	$	-		$	-	$	-		$	3.5
Identifiable assets		1,480.0		482.2		588.5			239.7		15.8			2,806.2
Unconsolidated investments		-		19.2		-			-		-			19.2
Capital expenditures		43.9		35.2		(0.2	)		-		-			78.9
Revenues by type:
Commodity Sales	$	1,652.5	$	-	$	4,889.3		$	1,294.6	$	(1,118.1	)	$	6,718.3
Services		7.2		195.1		30.3			0.6		(114.3	)		118.9
Other		1.8		-		3.8			0.8		0.1			6.5
	$	1,661.5	$	195.1	$	4,923.4		$	1,296.0	$	(1,232.3	)	$	6,843.7

The following table is a reconciliation of operating margin to net income for each period presented:

	Year Ended December 31,
	2009			2008			2007
Reconciliation of operating margin to net income:
Operating margin	$	324.9		$	297.3		$	322.1
Depreciation and amortization expense		(101.2	)		(97.8	)		(93.5	)
General and administrative expense		(78.9	)		(68.6	)		(64.0	)
Interest expense, net		(95.4	)		(97.1	)		(99.4	)
Income tax expense		(1.0	)		(2.4	)		(2.5	)
Other, net		5.8			18.3			(27.5	)
Net income	$	54.2		$	49.7		$	35.2

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Note 20—Other Operating Income

Our other operating (income) expense consists of the following items for the periods indicated:

	Year Ended December 31,
	2009			2008			2007
Casualty loss adjustment (see Note 12)	$	(0.8	)	$	5.0		$	-
Loss (gain) on sale of assets		-			(5.9	)		(0.3	)
	$	(0.8	)	$	(0.9	)	$	(0.3	)

Note 21—Supplemental Cash Flow Information

The following table provides supplemental cash flow information for each period presented:

	Year Ended December 31,
	2009		2008		2007
Cash:
Interest paid	$	27.0	$	29.3	$	15.5
Non-cash:
Net settlement of allocated indebtedness and debt issue costs		287.3		-		941.5
Net contribution of affiliated receivables		-		-		184.5
Non-cash long-term debt allocation of payments from Parent		-		-		(419.3	)
Debt issue costs allocated from Parent		-		-		(9.7	)
Like-kind exchange of property, plant and equipment		-		5.8		-
Inventory line-fill transferred to property, plant and equipment		9.8		-		(0.2	)
Issuance of Common Units in Downstream Acquisition		129.8		-		-
Issuance of General Partner Units in Downstream Acquisition		2.7		-		-

Note 22—Significant Risks and Uncertainties

Nature of Operations in Midstream Energy Industry

We operate in the midstream energy industry. Our business activities include gathering, transporting, processing, fractionating and storage of natural gas, NGLs and crude oil. Our results of operations, cash flows and financial condition may be affected by (i) changes in the commodity prices of these hydrocarbon products and (ii) changes in the relative price levels among these hydrocarbon products. In general, the prices of natural gas, NGLs, condensate and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.

Our profitability could be impacted by a decline in the volume of natural gas, NGLs and condensate transported, gathered or processed at our facilities. A material decrease in natural gas or condensate production or condensate refining, as a result of depressed commodity prices, a decrease in exploration and development activities or otherwise, could result in a decline in the volume of natural gas, NGLs and condensate handled by our facilities.

A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduced demand by consumers for the end products made with NGL products, (iii) increased competition from petroleum-based products due to the pricing differences, (iv) adverse weather conditions, (v) government regulations affecting commodity prices and production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could also adversely affect our results of operations, cash flows and financial position.

F - 39

Counterparty Risk with Respect to Financial Instruments

Where we are exposed to credit risk in our financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement, establishes credit and/or margin limits and monitors the appropriateness of these limits on an ongoing basis. Generally, management does not require collateral and does not anticipate nonperformance by our counterparties.

We have master netting agreements with most of our hedge counterparties. These netting agreements allow us to net settle asset and liability positions with the same counterparties. As of December 31, 2009, we had $7.4 million in liabilities to offset the default risk of counterparties with which we also had asset positions of $25.9 million as of that date.

Casualty or Other Risks

Targa maintains coverage in various insurance programs on our behalf, which provides us with property damage, business interruption and other coverages which are customary for the nature and scope of our operations.

Management believes that Targa has adequate insurance coverage, although insurance may not cover every type of interruption that might occur. As a result of insurance market conditions, premiums and deductibles for certain insurance policies have increased substantially, and in some instances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, Targa may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all.

If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts the revenues generated by us, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to meet our financial obligations.

A portion of the insurance costs described above is allocated to us by Targa through the allocation methodology as prescribed in the Omnibus Agreement described in Note 15.

Under the Omnibus Agreement, Targa has also indemnified us for losses attributable to rights-of-way, certain consents or governmental permits, pre-closing litigation relating to the North Texas System and income taxes attributable to pre-closing operations that were not reserved on the books of the North Texas System as of February 14, 2007. Targa does not have any obligation under these indemnifications until our aggregate losses exceed $250,000. We have indemnified Targa for all losses attributable to the post-closing operations of the North Texas System. Targa’s obligations under this additional indemnification will survive for three years from February 14, 2007, except that the indemnification for income tax liabilities will terminate upon the expiration of the applicable statutes of limitations.

F - 40

Note 23—Selected Quarterly Financial Data (Unaudited)

Our results of operations by quarter for the years ended December 31, 2009 and 2008, as adjusted to reflect the consideration of common control accounting as discussed in Note 2, were as follows:

	First Quarter			Second Quarter		Third Quarter			Fourth Quarter		Total
	(In millions, except per unit amounts)
Year Ended December 31, 2009:
Revenues	$	916.0		$	916.3	$	1,008.5		$	1,254.8	$	4,095.6
Operating income		18.7			32.7		39.4			54.8		145.6
Net income (loss)		(5.4	)		9.3		10.9			39.4		54.2
Net income (loss) per limited partner unit - basic and diluted		(0.09	)		0.10		0.17			0.56		0.86
Year Ended December 31, 2008:
Revenues	$	2,085.3		$	2,128.3	$	2,222.5		$	1,066.0	$	7,502.1
Operating income (loss)		45.2			67.9		(7.4	)		26.1		131.8
Net income (loss)		22.8			45.0		(38.1	)		20.0		49.7
Net income per limited partner unit - basic and diluted		0.50			0.54		0.31			0.48		1.83

As discussed in Note 3, we recorded an adjustment in the third quarter of 2009 related to prior period natural gas transactions which increased revenues, operating income, and net income by $1.8 million.

The following table reconciles the previously reported amounts to those shown above. This table show the first and second quarter 2009 adjustments applicable to our acquisition of the Downstream Business:

	Historical Targa Resources Partners LP			Downstream Business			Adjustments			Targa Resources Partners LP
First Quarter 2009
Revenues	$	239.0		$	764.4		$	(87.4	)	$	916.0
Operating income		7.4			11.3			-			18.7
Net income (loss)		(2.1	)		(3.3	)		-			(5.4	)
Net loss per limited partner unit - basic and diluted		(0.09	)		-			-			(0.09	)
Second Quarter 2009
Revenues	$	240.7		$	779.5		$	(103.9	)	$	916.3
Operating income		16.7			16.0			-			32.7
Net income (loss)		6.5			2.8			-			9.3
Net income per limited partner unit - basic and diluted		0.10			-			-			0.10

F - 41

During 2009, we reclassified NGL marketing fractionation and other service fees to revenues that were originally recorded in product purchase costs. This reclassification had no impact on our income from operations, net income, financial position or cash flows. The following table reconciles the previously reported amounts for the periods indicated.

	Revenues As Reported		Adjustments		Adjusted Revenues
First Quarter 2008	$	2,079.5	$	5.8	$	2,085.3
Second Quarter 2008		2,120.2		8.1		2,128.3
Third Quarter 2008		2,214.9		7.6		2,222.5
Fourth Quarter 2008		1,058.9		7.1		1,066.0
First Quarter 2009		912.3		3.7		916.0
Second Quarter 2009		906.1		10.2		916.3
Third Quarter 2009		1,003.8		4.7		1,008.5

F - 42