form10_k.htm
 



 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-K
 

R
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2008
 
or

¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
 OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from                     to
 
Commission file number: 001-33303
 
TARGA RESOURCES PARTNERS LP
(Exact name of registrant as specified in its charter)


Delaware
 
65-1295427
(State or other jurisdiction 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
 
The NASDAQ Stock Market LLC
 
 
Securities registered pursuant to section 12(g) of the Act: None
 

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes R 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 R
Accelerated filer *
Non-accelerated filer *
Smaller reporting company *
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act). Yes * No R.

The aggregate market value of the Common Units representing limited partner interests held by non-affiliates of the registrant was approximately $796.0 million on June 30, 2008, based on $23.05 per unit, the closing price of the Common Units as reported on The NASDAQ Stock Market LLC on such date.

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

DOCUMENTS INCORPORATED BY REFERENCE
 
None
 
 

 



 
TABLE OF CONTENTS
 
DESCRIPTION
 
   
  
   
         
 
1.
  
    2
 
 
1A.
 
   19
 
 
1B.
  
   39  
 
2.
  
   40  
 
3.
  
   40  
 
4.
  
   40  
         
   
  
   
         
 
5.
  
   41
 
 
6.
  
   43  
 
7.
  
   48
 
 
7A.
  
   68  
 
8.
  
   71  
 
9.
  
   71  
 
9A.
  
   71  
 
9B.
  
   71  
         
   
  
   
         
 
10.
  
   72  
 
11.
  
   76  
 
12.
  
   91  
 
13.
  
   93  
 
14.
  
   99  
         
   
  
   
         
 
15.
  
  100  





PART I

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

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

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

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

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

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


Bbl
Barrels (equal to 42 gallons)
BBtu
Billion British thermal units, a measure of heating value
Bcf
Billion cubic feet
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-HSC
Inside FERC Gas Market Report, Houston Ship Channel/Beaumont, Texas
IF-NGPL MC
MC Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
IF-Waha
Inside FERC Gas Market Report, West Texas Waha
NY-HH
NYMEX, Henry Hub Natural Gas
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 (NASDAQ: NGLS) is a growth-oriented Delaware limited partnership formed on October 26, 2006 by our parent, Targa Resources, Inc. (“Targa”), a leading provider of midstream natural gas and NGL services in the U.S., to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. We are engaged in the business of gathering, compressing, treating, processing and selling natural gas and fractionating and selling NGL and NGL products.

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



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

Business Strategies

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

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

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

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

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

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

·  
eliminate bottlenecks to allow for increased throughput;

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

·  
expand our footprint in a cost effective manner.

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



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

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

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

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

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

·  
where permitting, drilling and workover activity is high;

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

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

·  
Pursuing strategic and accretive acquisitions. We plan to pursue strategic and accretive acquisition opportunities within the midstream energy industry, both from Targa and from third parties. We will seek acquisitions in our existing areas of operation that provide the opportunity for operational efficiencies, the potential for higher capacity utilization and expansion of existing assets, acquisitions in other related midstream businesses and/or expansion into new geographic areas of operation and, to the extent available, assets with fee-based arrangements. Among the factors we will consider in deciding whether to acquire assets include, but are not limited to, the economic characteristics of the acquisition (such as return on capital and cash flow stability), the region in which the assets are located (both regions contiguous to our areas of operation and other regions with attractive characteristics) and the availability and sources of capital to finance the acquisition. We intend to finance our expansion through a combination of debt and equity, including commercial debt facilities and public and private offerings of debt and equity securities. Current disruptions in the financial markets has made obtaining equity or debt funding on acceptable terms more difficult, which could limit our ability to successfully complete acquisitions.

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


Competitive Strengths

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

·  
Affiliation with Targa. We expect that our relationship with Targa will provide us with significant business opportunities. Targa owns and operates a large integrated platform of midstream assets in oil and natural gas producing regions, including the Permian Basin in West Texas and Southeast New Mexico and the onshore and offshore regions of the Texas and Louisiana Gulf Coast. These operations are integrated with Targa’s NGL logistics and marketing business that extends services to customers throughout the U.S. We believe Targa’s relationships throughout the energy industry, including with producers of natural gas in the U.S., will help facilitate implementation of our acquisition strategy and other strategies. Targa has indicated that it intends to use us as a growth vehicle to pursue the acquisition and expansion of midstream natural gas, NGL and other complementary energy businesses and assets and we expect to have the opportunity, but not the obligation, to acquire such businesses and assets directly from Targa in the future.

·  
Strategically located assets. 

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

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

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

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

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

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

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



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

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

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

Our Relationship with Targa Resources, Inc.

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

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

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



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

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

Targa has a significant indirect interest in our partnership through its ownership of a 24.5% limited partner interest and a 2% general partner interest in us. In addition, Targa owns incentive distribution rights that entitle Targa to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. We are party to an Omnibus Agreement with Targa that governs our relationship with them regarding certain reimbursement and indemnification matters. See “Item 13. Certain Relationships and Related Transactions, and Director Independence—Omnibus Agreement.” In addition to carrying out operations, our general partner and its affiliates, which are indirectly owned by Targa, employ approximately 950 people, some of whom provide direct support to our operations. We do not have any employees. See “—Employees.”

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



Our Systems

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

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

Facility
Location
Approximate Gross Processing Capacity  (MMcf/d)
2008
Approximate
Gross Inlet
Throughput
Volume
(MMcf/d)
2008
Approximate
Gross NGL
Production
(MBbl/d)
Process
Type (3)
 
 
 
 
 
 
North Texas System
 
 
 
 
 
Chico (1)
Wise, TX
265
 
 
Cryo
Shackelford
Shackelford,TX
13
 
 
Cryo
 
Area Total
278
162.8
19.0
 
 
 
 
 
 
 
SAOU System
 
 
 
 
 
Mertzon
Irion, TX
48
 
 
Cryo
Sterling
Sterling, TX
62
 
 
Cryo
Conger (2)
Sterling, TX
25
 
 
Cryo
 
Area Total
135
90.3
14.1
 
 
 
 
 
 
 
LOU System
 
 
 
 
 
Gillis (1)
Calcasieu,LA
180
 
 
Cryo
Acadia
Acadia, LA
80
 
 
Cryo
 
Area Total
260
168.1
9.0
 

_____________

(1)  
The Chico and Gillis plants have fractionation capacities of approximately 15 MBbl/d and 13 MBbl/d.
(2)  
The Conger plant is not currently operating, but is on standby and can be quickly reactivated on short notice to meet additional needs for processing capacity.
(3)  
Cryo — Cryogenic Expander.

The North Texas System

The North Texas System includes two interconnected gathering systems with approximately 4,100 miles of pipelines, covering portions of 12 counties and 5,700 square miles, that gather wellhead natural gas for the Chico and Shackelford natural gas processing facilities. During 2008, the North Texas System gathered approximately 169 MMcf/d of natural gas.



Gathering. The Chico Gathering System consists of approximately 2,000 miles of primarily low-pressure gathering pipelines. Wellhead natural gas is either gathered for the Chico plant located in Wise County, Texas and then compressed for processing or it is compressed in the field at numerous compressor stations and then moved via one of several high-pressure gathering pipelines to the Chico plant. The Shackelford Gathering System consists of approximately 2,100 miles of intermediate-pressure gathering pipelines which gather wellhead natural gas largely for the Shackelford plant in Albany, Texas. Natural gas gathered from the northern and eastern portions of the Shackelford Gathering System is typically compressed in the field at numerous compressor stations and then transported via a high-pressure 32-mile, 10-inch diameter pipeline, called the Interconnect Pipeline, to the Chico plant for processing.

Processing. The Chico processing plant includes two cryogenic processing trains with a combined capacity of approximately 265 MMcf/d and an NGL fractionator with the capacity to fractionate up to approximately 15 MBbl/d of raw NGL mix. The Shackelford plant is a cryogenic plant with a nameplate capacity of approximately 15 MMcf/d, but effective capacity is limited to approximately 13 MMcf/d due to capacity constraints on the residue gas pipeline that serves the facility. Our produced NGL is primarily shipped via pipeline to Targa’s Mont Belvieu facility for fractionation.  Residue gas and NGL are shipped via several interstate and intrastate natural gas pipelines.  

The SAOU System

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

Gathering. The SAOU System is connected to numerous producing wells and/or central delivery points. The system has approximately 850 miles of low-pressure gathering systems and approximately 500 miles of high-pressure gathering pipelines to deliver the natural gas to our processing plants. The gathering system has numerous compressor stations to inject low-pressure gas into the high-pressure pipelines.

Processing. The SAOU System includes two currently operating refrigerated cryogenic processing plants, the Mertzon plant and the Sterling plant, which have an aggregate processing capacity of approximately 110 MMcf/d. The system also includes the Conger cryogenic plant with a capacity of approximately 25 MMcf/d, which is on standby and can be quickly reactivated on short notice and minimal incremental cost to meet additional needs for processing capacity. NGL produced by the SAOU system are primarily shipped via pipeline to Targa’s Mont Belvieu facility for fractionation.  Residue gas and NGL are shipped via several interstate and intrastate pipelines.

The LOU System

The LOU System consists of approximately 850 miles of gathering system pipelines, covering approximately 3,800 square miles in Southwest Louisiana. During 2008, the system gathered approximately 178 MMcf/d of natural gas, including approximately 53 MMcf/d purchased from third party pipeline systems.

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

Processing. The LOU System includes the Gillis and Acadia processing plants, both of which are cryogenic plants. These processing plants have an aggregate processing capacity of approximately 260 MMcf/d. In addition, the Gillis plant has integrated fractionation with operating capacity of approximately 13 MBbl/d of capacity. The residue gas produced from the processing plants has direct access to the Lake Charles industrial market through the system’s intrastate pipeline system. This intrastate system has the ability to deliver natural gas to industrial users and electric utilities in the Lake Charles area through both medium pressure and high pressure pipelines.



The Combined Systems

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

Our largest natural gas supplier for 2008 was Crosstex Energy (“Crosstex”), a gas gatherer who accounted for approximately 12% of our supply, which sells gas to us on a spot basis. In addition, purchases from ConocoPhillips accounted for approximately 11% of our combined gathering volumes in 2008. The loss of all or even a portion of the natural gas volumes supplied by these customers or the extension or replacement of these contracts on less favorable terms, if at all, as a result of competition or otherwise, could reduce our revenue or increase our cost for product purchases. 

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

Regulation of Operations

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

Gathering Pipeline Regulation

Our natural gas gathering operations are typically subject to ratable take and common purchaser statutes in the states in which we operate. The common purchaser statutes generally require our gathering pipelines to purchase or take without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we operate have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. The rates we charge for gathering are deemed just and reasonable unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties.



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

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

Intrastate Pipeline Regulation

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

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

Our Louisiana intrastate pipeline, Targa Louisiana Intrastate LLC, or TLI, owns an approximately 60-mile intrastate pipeline system that receives all of the natural gas it transports within or at the boundary of the State of Louisiana. Because all such gas ultimately is consumed within Louisiana, and since the pipeline’s rates and terms of service are subject to regulation by the Office of Conservation of the Louisiana Department of Natural Resources (“DNR”), the pipeline qualifies as a Hinshaw pipeline under Section 1(c) of the NGA and thus is exempt from full FERC regulation. On November 20, 2008, FERC issued a Notice of Inquiry (“NOI”) seeking comment on whether it should impose additional posting and reporting requirements on Hinshaw pipelines providing interstate service under limited blanket certificates and intrastate pipelines providing interstate service under Section 311 of the Natural Gas Policy Act, or NGPA.  If FERC issues a proposed rulemaking based on the NOI, it would not cover TLI as currently written, as TLI only provides service governed by the Hinshaw amendment. TLI does not provide interstate service pursuant to any limited blanket certificate.  FERC has not yet determined whether a rulemaking proceeding is necessary and we cannot predict what, if any, rules FERC will propose as a result of its inquiry or the ultimate impact of any such regulatory changes to our Hinshaw pipeline.



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

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

 
Natural Gas Processing
 
Our natural gas gathering and processing operations are not presently subject to FERC regulation. Starting May 1, 2009, we report to FERC information regarding natural gas sale and purchase transactions for some of our operations depending on the volume of natural gas transacted during the prior calendar year. See below the discussion of “FERC Market Transparency Rules.” There can be no assurance that our processing operations will continue to be exempt from other FERC regulation in the future.

Availability, Terms and Cost of Pipeline Transportation

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

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


Sales of Natural Gas and NGLs
 
The price at which we buy and sell natural gas and NGLs is currently not subject to federal 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 below the discussion of “Other Federal Laws and Regulations Affecting Our Industry – Energy Policy Act of 2005.” Starting May 1, 2009, we may be required to report to FERC information regarding natural gas sale and purchase transactions for some of our operations depending on the volume of natural gas transacted during the prior calendar year. See below the discussion “FERC Market Transparency Rules.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.


 
Other State and Local Regulation of Our Operations

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

Other Federal Laws and Regulation Affecting Our Industry

Energy Policy Act of 2005

 
The Domenici-Barton Energy Policy Act of 2005 (“EP Act 2005”) is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, EP Act 2005 amends the NGA to add an anti- market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act 2005 provides the FERC with the power to assess civil penalties of up to $1 million per day for violations of the NGA and $1 million per violation per day for violations of the NGPA. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. In 2006, FERC issued Order 670 to implement the anti-market manipulation provision of EP Act 2005. Order 670 makes it unlawful to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit  any statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. Order 670 does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704 and the daily schedule flow and capacity posting requirements under Order 720. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

FERC Market Transparency Rules

In 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers, are now required to report, on May 1 of each year, beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which transactions should be reported based on the guidance of Order 704.

On November 20, 2008, FERC issued a final rule on daily scheduled flows and capacity posting requirements (“Order 720”). Under Order 720, certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtu of gas over the previous three (3) calendar years, are required to post daily certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000 MMBtu per day. Requests for clarification and rehearing of Order 720 have been filed at FERC and a decision on those requests is pending.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such FERC action materially differently than other midstream natural gas companies with whom we compete.



Environmental, Health and Safety Matters

General
 
Our operations are subject to stringent and complex federal, state and local laws and regulations pertaining to health, safety and the environment. For more information on our operations, see “Item 1. Business—Our Systems”. As with the industry generally, compliance with current and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain and upgrade equipment and facilities. These laws and regulations may, among other things, require the acquisition of various permits to conduct regulated activities, require the installation of pollution control equipment or otherwise restrict the way we can handle or dispose of our wastes; limit or prohibit construction activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; require investigatory and remedial action to mitigate pollution conditions caused by our operations or attributable to former operations; and enjoin some or all of the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations. Failure to comply with these laws and regulations may result in assessment of administrative, civil and criminal penalties, the imposition of removal or remedial obligations and the issuance of injunctions limiting or prohibiting our activities.
 
We have implemented programs and policies designed to keep our pipelines, plants and other facilities in compliance with existing environmental laws and regulations. The clear trend in environmental regulation, however, is to place more restrictions and limitations on activities that may affect the environment and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, there is no assurance that the current conditions will continue in the future.
 
The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
 
Hazardous Substances and Waste
 
The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, (“CERCLA” or the “Superfund” law) and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the federal Environmental Protection Agency (“EPA”) and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. We generate materials in the course of our operations that are regulated as “hazardous substances” under CERCLA or similar state statutes and, as a result, may be jointly and severally liable under CERCLA or such statutes for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.



We also generate solid wastes, including hazardous wastes that are subject to the requirements of the federal Resource Conservation and Recovery Act, as amended (“RCRA”) and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of our operations we generate petroleum product wastes and ordinary industrial wastes such as paint wastes, waste solvents and waste compressor oils that are regulated as hazardous wastes. Certain materials generated in the exploration, development or production of crude oil and natural gas are excluded from RCRA’s hazardous waste regulations. However, it is possible that future changes in law or regulation could result in these wastes, including wastes currently generated during our operations, being designated as “hazardous wastes” and therefore subject to more rigorous and costly disposal requirements. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses as well as those of the oil and gas industry in general.
 
We currently own or lease and have in the past owned or leased, properties that for many years have been used for midstream natural gas and NGL activities. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) and to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.
 
Air Emissions
 
The Clean Air Act, as amended and comparable state laws and regulations restrict the emission of air pollutants from many sources, including processing plants and compressor stations and also impose various monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. We are currently reviewing the air emissions monitoring systems at certain of our facilities. We may be required to incur capital expenditures in the next few years to implement various air emissions leak detection and monitoring programs as well as to install air pollution control equipment or non-ambient storage tanks as a result of our review or in connection with maintaining, amending or obtaining operating permits and approvals for air emissions. We currently believe, however, that such requirements will not have a material adverse affect on our operations.
 
Global Warming and Climate Control
 
In response to concerns suggesting that emissions of certain gases, commonly referred to as “greenhouse gases” (including carbon dioxide (“CO2”) and methane), are contributing to the warming of the Earth’s atmosphere, the United States Congress has been  considering legislation to reduce such emissions. In addition, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or greenhouse gas cap and trade programs. As an alternative to cap and trade programs, Congress may consider the implementation of a carbon tax program. The cap and trade programs could require major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries or gas processing plants, to acquire and surrender emission allowances. Depending on the particular program, we could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations (e.g., compressor stations) or from combustion of fuels (e.g., natural gas or NGLs) we process. Depending on the design and implementation of carbon tax programs, our operations could face additional taxes and higher cost of doing business. Although we would not be impacted to a greater degree than other similarly situated gatherers and processors of natural gas or NGLs, a stringent greenhouse gas control program could have an adverse effect on our cost of doing business and could reduce demand for the natural gas and NGLs we gather and process.
 


Also, as a result of the U.S. Supreme Court’s decision in 2007 in Massachusetts, et al. v. EPA, the EPA may regulate greenhouse gas emissions from mobile sources such as cars and trucks even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases including CO2 fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of CO2 and other greenhouse gas emissions from stationary sources. In July 2008, EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act, in response to the Supreme Court's decision in Massachusetts. In the notice, EPA evaluated the potential regulation of greenhouse gases under the Clean Air Act and other potential methods of regulating greenhouse gases. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such new federal or state restrictions on emissions of CO2 that may be imposed in areas in which we conduct business could also have an adverse affect on our cost of doing business and demand for the natural gas and NGLs we gather and process.
 
Water Discharges
 
The Federal Water Pollution Control Act, as amended (“Clean Water Act” or “CWA”) and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters. Pursuant to the CWA and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the U.S. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by EPA or the analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff. The CWA and analogous state laws can impose substantial civil and criminal penalties for non-compliance including spills and other non-authorized discharges.
 
The Oil Pollution Act of 1990, as amended (“OPA”), which amends the CWA, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” under OPA includes owners and operators of onshore facilities, such as our plants and our pipelines. Under OPA, owners and operators of facilities that handle, store, or transport oil are required to develop and implement oil spill response plans, and establish and maintain evidence of financial responsibility sufficient to cover liabilities related to an oil spill for which such parties could be statutorily responsible. We believe that we are in substantial compliance with the CWA, OPA and analogous state laws.
 
Endangered Species Act
 
The federal Endangered Species Act, as amended (“ESA”), restricts activities that may affect endangered or threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.
 


Pipeline Safety
 
The pipelines we use to gather and transport natural gas and transport NGLs are subject to regulation by the United States Department of Transportation, or the DOT, under the Natural Gas Pipeline Safety Act of 1968, as amended, or NGPSA, with respect to natural gas and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with respect to crude oil, NGLs and condensates. The NGPSA and HLPSA govern the design, installation, testing, construction, operation, replacement and management of natural gas and NGL pipeline facilities. Pursuant to these acts, the DOT has promulgated regulations governing pipeline wall thickness, design pressures, maximum operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures. Where applicable, the NGPSA and HLPSA require any entity that owns or operates pipeline facilities to comply with the regulations under these acts, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that our pipeline operations are in substantial compliance with applicable NGPSA and HLPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, future compliance with the NGPSA and HLPSA could result in increased costs.
 
Our pipelines are also subject to regulation by DOT under the Pipeline Safety Improvement Act of 2002, which was amended by the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (“PIPES Act”). DOT, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a series of rules, which require pipeline operators to develop and implement integrity management programs for gas transmission pipelines that, in the event of a failure, could affect “high consequence areas.” “High consequence areas” are currently defined as areas with specified population densities, buildings containing populations of limited mobility and areas where people gather that are located along the route of a pipeline. Similar rules are also in place for operators of hazardous liquid pipelines including lines transporting NGLs and condensates.
 
In addition, states have adopted regulations, similar to existing DOT regulations, for intrastate gathering and transmission lines. Texas and Louisiana have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastate pipelines transporting natural gas and NGLs. We currently estimate an annual average cost of $0.4 million for years 2009 through 2011 to perform necessary integrity management program testing on our pipelines required by existing DOT and state regulations. This estimate does not include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which costs could be substantial. However, we do not expect that any such costs would be material to our financial condition or results of operations.
 
More recently, in September 2008, PHMSA issued a proposed rule mandated by the PIPES Act focusing on how human interactions of control room personnel, such as avoidance of error or the performance of mitigating actions, may impact pipeline system integrity. Among other things, the proposed rule would require operators of hazardous liquid and gas pipelines to amend their existing written operations and maintenance procedures, operator qualification programs and emergency plans to take into account such items as specificity of the responsibilities and roles of control room personnel; listing of planned pipeline-related occurrences during a particular shift that may be easily shared with other controllers during a shift turnover; establishment of appropriate shift rotations to protect against controller fatigue; and development of appropriate communications between controllers, management and field personnel when planning and implementing changes to pipeline equipment or operations. While we do not anticipate that the rule, as proposed, will result in substantial costs with respect to our operations, the rule is not yet finalized and thus we cannot provide assurance on how significant an impact the rule ultimately will have on our operations, once it is adopted.
 


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

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

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

Employees

To carry out its operations, Targa employs approximately 950 people, some of whom provide direct support for our operations. None of these employees are covered by collective bargaining agreements. Targa considers its employee relations to be good. We do not have any employees.

Available Information

We make certain filings with the Securities and Exchange Commission (“SEC”), including our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments and exhibits to those reports, available free of charge through our website, http://www.targaresources.com, as soon as reasonably practicable after they are filed with the SEC. The filings are also available through (1) the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549, (2) by calling 1-800-SEC-0330 and (3) on the internet at http://www.sec.gov. Our press releases and recent analyst presentations are also available on our website.




Item 1A. Risk Factors 

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

Risks Related to Our Business

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

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

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

In addition, in October 2008, Lehman Brothers Commercial Bank (“Lehman Bank”) defaulted on a borrowing request under our senior secured revolving credit facility (“credit facility”) which effectively reduced our total commitments under our credit facility by approximately $10.0 million. We can provide no assurance that other lending counterparties will be willing or able to meet their existing funding obligations under our credit facility.

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

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

We currently have a substantial amount of indebtedness. As of December 31, 2008 we had approximately $696.8 million of total indebtedness outstanding, approximately $9.7 million of letters of credit outstanding and $342.5 million of additional borrowing capacity under our credit facility. In October 2008, one of the lenders under our credit facility, Lehman Bank, defaulted on a borrowing request. As a result, we believe the total commitments under the credit facility have been effectively reduced by approximately $10.0 million. Our credit facility allows us to request increases in the commitments under the credit facility of up to $150 million. We may also incur additional indebtedness in the future.

Our substantial indebtedness may:

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

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



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

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

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

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

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

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

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

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

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

·  
the impact of seasonality and weather;

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

·  
the economic conditions of our customers;

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

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

·  
actions taken by foreign oil and gas producing nations;

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

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

·  
the impact of energy conservation efforts; and

·  
the extent of governmental regulation and taxation.



Our primary natural gas gathering and processing arrangements that expose us to commodity price risk are our percent-of-proceeds arrangements. For the year ended December 31, 2008, our percent-of-proceeds arrangements accounted for approximately 77% of our gathered natural gas volume. Under percent-of-proceeds arrangements, we generally process natural gas from producers and remit to the producers an agreed percentage of the proceeds from the sale of residue gas and NGL products at market prices or a percentage of residue gas and NGL products at the tailgate of our processing facilities. In some percent-of-proceeds arrangements, we remit to the producer a percentage of an index or index-based price for residue gas and NGL products, less agreed adjustments, rather than remitting a portion of the actual sales proceeds. Under these types of arrangements, our revenues and our cash flows increase or decrease, whichever is applicable, as the prices of natural gas, NGL and crude oil fluctuate. For additional information regarding our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk —Commodity Price Risk.”

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

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

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

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

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



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

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

We depend on two natural gas producers for a significant portion of our supply of natural gas. The loss of these customers or the replacement of their contracts on less favorable terms could result in a decline in our volumes, revenues and cash available for distribution.

Our largest natural gas supplier for 2008 was Crosstex, a gas gatherer who accounted for approximately 12% of our supply, which sells gas to us on a spot basis. In addition, purchases from ConocoPhillips accounted for approximately 11% of our combined gathering volumes in 2008. The loss of all or even a portion of the natural gas volumes supplied by these customers or the extension or replacement of these contracts on less favorable terms, if at all, as a result of competition or otherwise, could reduce our revenue or increase our cost for product purchases, impairing our ability to make distributions to our unitholders. 

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

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

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

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

Our acquisitions involve numerous risks, including:

·  
operating a significantly larger combined organization and adding operations;

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



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

·  
the failure to realize expected profitability or growth;

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

·  
coordinating geographically disparate organizations, systems and facilities.

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

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

We have entered into purchase agreements with Targa pursuant to which Targa will purchase (i) all of the North Texas System’s natural gas, NGLs and high-pressure condensate for a term of 15 years and (ii) substantially all of the SAOU and LOU Systems’ natural gas for a term of 15 years and NGLs for a term of one year. Targa also manages the SAOU and LOU Systems’ natural gas sales to third parties under contracts that remain in the name of the SAOU and LOU Systems. We are also party to an amended and restated Omnibus Agreement with Targa which addresses, among other things, the provision of general and administrative and operating services to us. Targa’s corporate credit ratings as assigned by Moody’s and Standard & Poors as of February 25, 2009 are B1 and B, which are speculative ratings. These speculative ratings signify a higher risk that Targa will default on its obligations, including its obligations to us, than does an investment grade credit rating. Any material nonperformance under the omnibus and purchase agreements by Targa could materially and adversely impact our ability to operate and make distributions to our unitholders.

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

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

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

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



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

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

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

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

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

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

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

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

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

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



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

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

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

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

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

·  
damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters, explosions and acts of terrorism;

·  
inadvertent damage from third parties, including from construction, farm and utility equipment;

·  
leaks of natural gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities; and

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



Increases in interest rates could adversely affect our business.

In addition to our exposure to commodity prices, we have significant exposure to increases in interest rates. As of December 31, 2008, we had approximately $487.8 million of debt outstanding under our credit facility at variable interest rates. Our results of operations, cash flows and financial condition could be materially adversely affected by significant increases in interest rates. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk —Interest Rate Risk.”

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

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

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

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

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

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



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

Our operations are subject to stringent and complex federal, state and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. For more information on our operations, see “Item 1. Business—Our Systems” for additional information on our operations. These laws include, for example, (1) the federal Clean Air Act and comparable state laws that impose obligations related to air emissions, (2) the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state laws that impose requirements for the handling, storage, treatment or disposal of solid and hazardous waste from our facilities, (3) the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”) also known as “Superfund,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which our hazardous substances have been transported for disposal and (4) the Federal Water Pollution Control Act (the “Clean Water Act”) and comparable state laws that regulate discharges of wastewater from our facilities to state and federal waters. Failure to comply with these laws and regulations or newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations. Certain environmental laws, including CERCLA and analogous state laws, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or waste products into the environment.

There is inherent risk of incurring environmental costs and liabilities in connection with our operations due to our handling of natural gas and other petroleum products, air emissions and water discharges related to our operations and historical industry operations and waste disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury, natural resource and property damages and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our operational or compliance costs and the cost of any remediation that may become necessary. In particular, we may incur expenditures in order to attain or maintain compliance with legal requirements governing emissions of air pollutants from our facilities. We may not be able to recover all or any of these costs from insurance. For further information on environmental matters, see “Item 1. Business— Environmental, Health and Safety Matters” for additional information on environmental matters.

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

The NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress.

While our natural gas gathering operations are generally exempt from FERC regulation under the NGA, our gas gathering operations may be subject to certain FERC reporting and posting requirements in a given year. FERC has recently issued a final rule (as amended by orders on rehearing, “Order 704”) requiring certain participants in the natural gas market, including intrastate pipelines, natural gas gatherers, natural gas marketers and natural gas processors, that engage in a minimum level of natural gas sales or purchases to submit annual reports regarding those transactions to FERC. In addition, FERC has issued a final rule (“Order 720”) requiring major non-interstate pipelines, defined as certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtus of gas over the previous three calendar years, to post daily certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has design capacity equal to or greater than 15,000 MMBtu per day.



Other FERC regulations may indirectly impact our businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, gas quality, ratemaking, capacity release and market center promotion, may indirectly affect the intrastate natural gas market. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to transportation capacity. For more information regarding the regulation of Targa’s operations, see “Item 1. Business—Regulation of Operations”.

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

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

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

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

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

Pursuant to the Pipeline Safety Improvement Act of 2002, as reauthorized and amended by the Pipeline Inspections, Protection, Enforcement and Safety Act of 2006, DOT, through the PHMSA, has adopted regulations requiring pipeline operators to develop integrity management programs for transmission pipelines located where a leak or rupture could do the most harm in “high consequence areas,” including high population areas, areas that are sources of drinking water, ecological resource areas that are unusually sensitive to environmental damage from a pipeline release and commercially navigable waterways, unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. The regulations require operators of covered pipelines to:

·  
perform ongoing assessments of pipeline integrity;

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

·  
improve data collection, integration and analysis;

·  
repair and remediate the pipeline as necessary; and

·  
implement preventive and mitigating actions.



In addition, states have adopted regulations similar to existing U.S. DOT regulations for intrastate gathering and transmission lines. We currently estimate that we will incur an aggregate cost of approximately $1.2 million between 2009 and 2011 to implement pipeline integrity management program testing along certain segments of our natural gas and NGL pipelines. This estimate does not include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which costs could be substantial. At this time, we cannot predict the ultimate cost of compliance with this regulation, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. Following the initial round of testing and repairs, we will continue our pipeline integrity testing programs to assess and maintain the integrity or our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operations of our pipelines.

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

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

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

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

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

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

·  
an inability to integrate successfully the businesses we acquire;

·  
the assumption of unknown liabilities;

·  
limitations on rights to indemnity from the seller;

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

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



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

·  
customer or key employee losses at the acquired businesses.

If these risks materialize, the acquired assets may inhibit our growth or fail to deliver expected benefits.

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

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

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

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

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

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

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

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

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

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



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

Risks Inherent in an Investment in Us

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

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

In order to make cash distributions at our current distribution rate of $0.5175 per common unit and subordinated unit per complete quarter or $2.07 per unit per year, we will require available cash of approximately $26.4 million per quarter or $105.4 million per year, based on common units and subordinated units outstanding as of December 31, 2008. We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at our current distribution rate under our cash distribution policy. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

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

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

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

·  
the relationship between natural gas and NGL prices;

·  
cash settlements of hedging positions;

·  
the level of competition from other midstream energy companies;

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

·  
prevailing economic conditions.

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

·  
the level of capital expenditures we make;

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

·  
the cost of acquisitions;

·  
our debt service requirements and other liabilities;

·  
fluctuations in our working capital needs;
 
 


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

·  
restrictions on distributions contained in our debt agreements; and

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

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

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

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

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

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

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

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

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

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

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

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

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



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

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

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

Targa is not limited in its ability to compete with us, which could limit our ability to acquire additional assets or businesses.

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

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

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

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

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



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

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

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

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

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

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

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

·  
the ratio of taxable income to distributions may increase;

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

·  
the market price of the common units may decline.

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

Management of our general partner and Targa beneficially hold 292,252 common units and 11,528,231 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier. The sale of these units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.

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

Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution amount.



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

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

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

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

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

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

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

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

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the end of the subordination period, assuming no additional issuances of common units, our general partner and its affiliates will own approximately 24.5% of our aggregate outstanding common units.



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

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

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

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

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

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

Tax Risks to Common Unitholders

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

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. In order to maintain our status as a partnership for United States federal income tax purposes, 90% or more of our gross income in each tax year must be qualifying income under section 7704 of the Internal Revenue Code. We have not requested and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. We have requested a ruling from the IRS with respect to the qualifying nature of the income earned as a result of a purchase of our debt at a discount upon which, if granted, we may rely with respect to such income. There can be no assurance that the IRS will provide such a favorable ruling. However, any income earned as a result of a purchase or our debt at a discount plus any other non-qualifying income we earned in 2008 is less than 10% of our total gross income.

Although we do not believe based upon our current operations that we are treated as a corporation for federal income tax purposes, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.



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

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

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

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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

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

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

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



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

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

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

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

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

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations and may result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

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

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



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

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

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

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

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest are counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine in a timely manner that a termination occurred.

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

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


Item 1B. Unresolved Staff Comments

None




Item 2. Properties

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

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


Item 3. Legal Proceedings

On December 8, 2005, WTG Gas Processing (“WTG”) filed suit in the 333rd District Court of Harris County, Texas against several defendants, including Targa Resources, Inc. and three other Targa entities and private equity funds affiliated with Warburg Pincus LLC, seeking damages from the defendants. The suit alleges that Targa and private equity funds affiliated with Warburg Pincus, along with ConocoPhillips Company (“ConocoPhillips”) and Morgan Stanley, tortiously interfered with (i) a contract WTG claims to have had to purchase the SAOU System from ConocoPhillips and (ii) prospective business relations of WTG. WTG claims the alleged interference resulted from Targa’s competition to purchase the ConocoPhillips’ assets and its successful acquisition of those assets in 2004. On October 2, 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s claims. WTG’s motion to reconsider and for a new trial was overruled. On January 2, 2008, WTG filed a notice of appeal. On February 3, 2009, the parties presented oral arguments and the appeal is pending before the 14th Court of Appeals in Houston, Texas.  We are contesting WTG’s appeal, but can give no assurances regarding the outcome of the proceeding. Targa has agreed to indemnify us for any claim or liability arising out of the WTG suit.

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


Item 4. Submission of Matters to a Vote of Security Holders

None


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 NASDAQ Stock Market LLC (“NASDAQ”) under the symbol “NGLS” since February 9, 2007. Prior to February 9, 2007, our equity securities were not listed on any exchange or traded on any public trading market. The following table sets forth the high and low sales prices of the common units, as reported by NASDAQ, as well as the amount of cash distributions declared for the period February 14, 2007 through December 31, 2008.


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


As of February 4, 2009, there were approximately 57 unitholders of record of our common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record. We have also issued 11,528,231 subordinated units, for which there is no established public trading market. The subordinated units are held by affiliates of Targa Resources GP LLC, our general partner. Our general partner and its affiliates will receive a quarterly distribution on these units only after sufficient funds have been paid to the common units. There is no established trading market for the 943,108 general partner units held by our general partner.

Distributions of Available Cash

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

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

·  
provide for the proper conduct of our business;

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

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



Minimum Quarterly Distribution. We intend to make cash distributions to the holders of common units and subordinated units on a quarterly basis in an amount equal to at least the minimum quarterly distribution of $0.3375 per unit or $1.35 per unit on an annualized basis, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. The board of directors of our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to our unitholders, reserves to reduce debt or, as necessary, reserves to comply with the term of any of our agreements or obligations. We will be prohibited from making any distributions to unitholders if it would cause an event of default or an event of default exists, under our credit agreement or indenture.

General Partner Interest. Our general partner is currently entitled to 2% of all quarterly distributions that we make prior to our liquidation. This general partner interest is represented by 943,108 general partner units. Our general partner has the right, but not the obligation, to contribute a proportional amount of capital to us to maintain its current general partner interest. The general partner’s 2% interest in these distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportional amount of capital to us to maintain its 2% general partner interest.

Incentive Distribution Rights. Our general partner also currently holds incentive distribution rights that entitle it to receive up to a maximum of 50% of the cash we distribute in excess of $0.5063 per unit per quarter. The maximum distribution of 50% includes distributions paid to our general partner on its general partner interest and assumes that our general partner maintains its general partner interest at 2%. The maximum distribution of 50% does not include any distributions that our general partner may receive on limited partner units that it owns.

Recent Sales of Unregistered Units

None

Repurchase of Equity by Targa Resources Partners LP

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

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



Item 6. Selected Financial Data

SELECTED FINANCIAL AND OPERATING DATA

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

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

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

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

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

 
 

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

______________

 
(1)
In May 2006, Texas adopted a margin tax consisting of a 1% tax on the amount by which total revenue exceeds cost of goods sold, as apportioned to Texas. The amount presented represents our estimated liability for this tax.
   
(2)
Operating margin is total operating revenues less product purchases and operating expense. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations—Operating Margin” and “—Non-GAAP Financial Measures.”
   
(3)
Adjusted EBITDA is net income before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations—Adjusted EBITDA” and “—Non-GAAP Financial Measures.”
   
(4)
Distributable Cash Flow is net income plus depreciation and amortization and deferred taxes, adjusted for losses/(gains) on mark-to-market derivative contracts and early extinguishment of debt, less maintenance capital expenditures. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Operations — Distributable Cash Flow” and “— Non-GAAP Financial Measures.”
   
(5)
Gathering throughput represents the volume of natural gas gathered and passed through natural gas gathering pipelines from connections to producing wells and central delivery points.
   
(6)
Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.
   
(7)
Plant inlet volumes include producer take-in-kind, while natural gas sales exclude producer take-in-kind volumes.
   
(8)
Average realized prices include the impact of hedging activities.


Non-GAAP Financial Measures

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

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

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

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



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

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


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




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

Operating Margin. We define operating margin as total operating revenues, which consist of natural gas and NGL sales plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases and operating expense. Management reviews operating margin monthly for consistency and trend analysis. Based on this monthly analysis, management takes appropriate action to maintain positive trends or to reverse negative trends. Management uses operating margin as an important performance measure of the core profitability of our operations.

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

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

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

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

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

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

______________




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

Distributable Cash Flow. Distributable cash flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks, research analysts and others to compare basic cash flows generated by us (prior to the establishment of any retained cash reserves by the board of directors of our general partner) to the cash distributions we expect to pay our unitholders. Using this metric, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable cash flow is also an important non-GAAP financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the value of a unit of such an entity is generally determined by the unit’s yield (which in turn is based on the amount of cash distributions the entity pays to a unitholder).

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

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

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


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

____________

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




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

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

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

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

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

Overview

We are a Delaware limited partnership formed by Targa to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. We are engaged in the business of gathering, compressing, treating, processing and selling natural gas and fractionating and selling NGLs and NGL products. We currently operate in the Fort Worth Basin in North Texas, the Permian Basin in West Texas and in Southwest Louisiana.

We are owned 98% by our limited partners and 2% by our general partner, Targa Resources GP LLC, an indirect, wholly-owned subsidiary of Targa. Our limited partner common units are publicly traded on the NASDAQ Stock Market LLC under the symbol “NGLS.”

Factors That Significantly Affect Our Results

Our results of operations are substantially impacted by changes in commodity prices as well as increases and decreases in the volume of natural gas that we gather, which we refer to as throughput volume. Throughput volumes and capacity utilization rates generally are driven by wellhead production, our competitive position on a regional basis and more broadly by prices and demand for natural gas and NGLs.

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




Contract Type
Percent of
Throughput
Impact of Commodity Prices
Percent-of-Proceeds
77%
Decreases in natural gas and/or NGL prices generate decreases in operating margin.
Wellhead Purchases/Keep Whole
20%
Increases in natural gas prices relative to NGL prices generate decreases in operating margin. Decreases in NGL prices relative to natural gas prices generate decreases in operating margin.
Hybrid
1%
In periods of favorable processing economics, similar to percent-of-proceeds (or wellhead purchases/keep-whole in some circumstances, if economically advantageous to the processor). In periods of unfavorable processing economics, similar to fee-based.
Fee Based
2%
No direct impact from commodity price movements.

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

We attempt to mitigate the price risk associated with our contract mix through hedging activities which can materially impact our results of operations. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Impact of Our Hedging Activities. In an effort to reduce the variability of our cash flows, we have hedged the commodity price associated with a portion of our expected natural gas, NGLs and condensate equity volumes for the years 2009 through 2012 by entering into derivative financial instruments including swaps and purchased puts (or floors). With these arrangements, we have attempted to mitigate our exposure to commodity price movements with respect to our forecasted volumes for this period. For additional information regarding our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

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

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

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

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

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



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

Allocated general and administrative expenses were $18.2 million, $15.6 million and $16.1 million for 2008, 2007 and 2006. For a more complete description of this agreement, see “Item 13. Certain Relationships and Related Transactions, and Director Independence—Omnibus Agreement.”

In addition to these allocated general and administrative expenses, we incur incremental general and administrative expenses as a result of operating as a separate publicly held limited partnership. These direct, incremental general and administrative expenses, which were approximately $4.2 million and $3.3 million during 2008 and 2007, including one-time expenses associated with our equity offerings, financing arrangements and acquisitions were  not subject to the cap contained in the Omnibus Agreement. These costs include costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, registrar and transfer agent fees and independent director compensation. These incremental general and administrative expenditures are not reflected in the historical financial statements of the North Texas, SAOU and LOU Systems.

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

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

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

On February 14, 2007, we borrowed approximately $294.5 million under our credit facility. The proceeds from this borrowing, together with approximately $371.2 million of net proceeds from our IPO (including 2,520,000 common units sold pursuant to the full exercise by the underwriters of their option to purchase additional common units), were used to repay approximately $665.7 million of affiliate indebtedness and the remaining balance of this indebtedness was retired and treated as a capital contribution to us.

On October 24, 2007, we completed our acquisition of the SAOU and LOU Systems concurrently with the sale of 13,500,000 common units representing limited partnership interests in us for gross proceeds of $362.7 million (approximately $349.2 million after underwriting discount and structuring fees). The net proceeds from the sale of the 13,500,000 units were used to pay approximately $2.5 million in expenses associated with the sale of the common units and $24.2 million to Targa for certain hedge transactions associated with the SAOU and LOU Systems. We used the net proceeds after offering expenses and the hedge transactions of $322.5 million along with net borrowings of $375.5 million to pay approximately $698.0 million of the acquisition costs of the SAOU and LOU Systems. The allocated indebtedness from Targa related to the SAOU and LOU Systems was $124.0 million. Targa debt was guaranteed by the entities that own the SAOU and LOU Systems and was secured by a collateral interest in both the equity interests of those entities as well as their underlying assets. In conjunction with our acquisition of the SAOU and LOU Systems, this guarantee was terminated, the collateral interest was released and the allocated indebtedness was retired.



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

Distributions to our Unitholders.

We intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.3375 per common unit per quarter ($1.35 per common unit on an annualized basis). Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including other debt and common unit issuances, to fund our acquisition and expansion capital expenditures, as well as our working capital needs. Historically, we have relied on internally generated cash flows for these purposes. Due to the timing of our IPO, a pro-rated distribution for the first quarter of 2007 of $0.16875 per common and subordinated unit was paid.

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

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

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

General Trends and Outlook

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

Natural Gas Supply and Outlook. Fluctuations in energy prices can affect production rates and investments by third parties in the development of new natural gas reserves. Generally, drilling and production activity will increase as natural gas prices increase and decrease as natural gas prices decrease. The recent substantial decline in natural gas prices has led many exploration and production companies to reduce planned capital expenditures for drilling and production activities during 2009 which could lead to a decrease in the level of natural gas production in our areas of operation.
 


Commodity Prices. Our operating income generally improves in an environment of higher natural gas, NGL and condensate prices, primarily as a result of our percent-of-proceeds contracts. Our processing profitability is largely dependent upon pricing and market demand for natural gas, NGLs and condensate, which are beyond our control and have been volatile. Due to the recent volatility, we are uncertain of what pricing and market demand for natural gas, NGLs and condensate will be throughout 2009. The current weak economic conditions have negatively affected the pricing and market demand for natural gas, NGLs and condensate, which has caused a reduction in the profitability of our processing operations. In a declining commodity price environment, without taking into account our hedges, we will realize a reduction in cash flows under our percent-of-proceeds contracts proportionate to average price declines. We have attempted to mitigate our exposure to commodity price movements by entering into hedging arrangements. For additional information regarding our hedging activities, see “—Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”
 
Volatile Capital Markets. We are dependent on our ability to access the equity and debt capital markets in order to fund acquisitions and expansion expenditures. Global financial markets have been and are expected to continue to be, extremely volatile and disrupted and the current weak economic conditions have recently caused a significant decline in commodity prices. As a result, we may be unable to raise equity or debt capital on satisfactory terms or at all, which may negatively impact the timing and extent to which we execute growth plans. Prolonged periods of low commodity prices or volatile capital markets may impact our ability or willingness to enter into new hedges, fund organic growth, connect to new supplies of natural gas, execute acquisitions or implement expansion capital expenditures.
 
Our Operations

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

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

How We Evaluate Our Operations

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

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



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

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

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

Operating Margin. We review performance based on the non-generally accepted accounting principle (“non-GAAP”) financial measure of operating margin. We define operating margin as total operating revenues, which consist of natural gas and NGL sales plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases and operating expense. Natural gas and NGL sales revenue includes settlement gains and losses on commodity hedges. Our operating margin is impacted by volumes and commodity prices as well as by our contract mix and hedging program, which are described in more detail below. We view our operating margin as an important performance measure of the core profitability of our operations. We review our operating margin monthly for consistency and trend analysis.

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

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


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

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



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

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

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

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

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

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

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

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

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

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

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

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



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

   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
   
(In millions)
 
Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
                 
Net cash provided by operating activities
  $ 95.2     $ 270.5     $ 124.4  
Allocated interest expense from parent (1)
    -       18.5       81.8  
Interest expense, net (2)
    36.2       21.1       -  
Gain on debt extinguishment
    13.1       -       -  
Early termination of commodity derivatives
    87.4       -       -  
Other
    (0.5 )     (0.1 )     (0.4 )
Changes in operating working capital which used (provided) cash:
                       
Accounts receivable and other assets
    (64.3 )     (88.8 )     (80.9 )
Accounts payable and other liabilities
    61.8       (35.4 )     29.2  
Adjusted EBITDA
  $ 228.9     $ 185.8     $ 154.1  
                         
Reconciliation of net income to Adjusted EBITDA:
                       
Net income
  $ 91.5     $ 40.3     $ 11.6