form10-k.htm

 
10-K 1 form10_k.htm FORM 10-K ANNUAL REPORT
 


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

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

For the fiscal year ended December 31, 2010
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: 001-34991
 
TARGA RESOURCES CORP.
(Exact name of registrant as specified in its charter)

Delaware
 
20-3701075
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
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 Stock
 
New York Stock Exchange
 

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

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

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

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. R

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

As of June 30, 2010, the last day of the registrant’s most recently completed second quarter, the registrant’s common stock was not publicly traded. As of February 22, 2011, the aggregate market value of the registrant’s common stock, $0.001 par value, held by non-affiliates of the registrant was approximately $719.7 million (based upon the closing sale price of $31.91 per common stock on that date on The New York Stock Exchange).

As of February 25, 2011, there were 42,349,738 shares of the registrant’s common stock, $0.001 par value, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None



 
 

 
 
 
 
 
 
 
DESCRIPTION
 
 
 
 
 
PART I
 
 
 
 
 5
 25
 40
 40
 40
 40
 
 
 
 
PART II
 
 
 
 
 41
 43
 43
 64
 67
 67
 67
 67
 
 
 
 
PART III
 
 
 
 
 68
 71
 85
 86
 90
 
 
 
 
PART IV
 
 
 
 
 91

 
2

 
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Targa Resources Corp.’s (together with its subsidiaries, other than Targa Resources Partners LP, collectively “we,” “us,” “Targa,” “TRC,” or the “Company”) 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.” You can typically identify forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, 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:

·  
Targa Resources Partners LP (the “Partnership”) and 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 the Partnership’s transactions;

·  
the Partnership’s 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 the Partnership’s services;

·  
weather and other natural phenomena;

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

·  
the Partnership’s ability to obtain necessary licenses, permits and other approvals;

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

·  
the Partnership’s and 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 in “Item 1A. Risk Factors” in this Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.
 
 
As generally used in the energy industry and in this Annual Report the identified terms have the following meanings:

Bbl
Barrels (equal to 42 gallons)
BBtu
Billion British thermal units
Btu
British thermal units, a measure of heating value
/d
Per day
gal
Gallons
MBbl
Thousand barrels
Mcf
Thousand cubic feet
MMBbl
Million barrels
MMBtu
Million British thermal units
MMcf
Million cubic feet
NGL
Natural gas liquid(s)
   
Price Index
 
Definitions
 
IF-NGPL MC
Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
IF-PB
Inside FERC Gas Market Report, Permian Basin
IF-WAHA
Inside FERC Gas Market Report, West Texas WAHA
NY-WTI
NYMEX, West Texas Intermediate Crude Oil
OPIS - MB
Oil Price Information Service, Mont Belvieu, Texas


 
PART I

Item 1. Business

Overview

Targa Resources Corp. (NYSE:TRGP) is a publicly traded Delaware corporation formed in October 2005. With the completion of the conveyance of all of our remaining operating assets to Targa Resources Partners LP (the “Partnership”) in September 2010, we no longer directly own any operating assets. Our main source of future revenue therefore is from general and limited partner interests, including incentive distribution rights (“IDRs”), in the Partnership, a publicly traded Delaware limited partnership (NYSE: NGLS) that is a leading provider of midstream natural gas and natural gas liquid services in the United States. The Partnership is engaged in the business of gathering, compressing, treating, processing and selling natural gas and storing, fractionating, treating, transporting and selling NGLs, and NGL products.

Initial Public Offering

On December 10, 2010, we completed an initial public offering, or IPO, of common shares in the Company. In the IPO, the selling shareholders, including a member of our senior management, sold 18,831,250 common shares at a price of $22.00 per share. We did not receive any proceeds from the sale of shares by the selling stock holders. On completion of the IPO, there were 42,292,348 shares outstanding.

Business of Targa Resources Corp.

Our primary business objective is to increase our cash available for dividends to our stockholders by assisting the Partnership in executing its business strategy. We may facilitate the Partnership’s growth through various forms of financial support, including, but not limited to, modifying the Partnership’s IDRs, exercising the Partnership’s IDR reset provision contained in its partnership agreement, making loans, making capital contributions in exchange for yielding or non-yielding equity interests or providing other financial support to the Partnership, if needed, to support its ability to make distributions. In addition, we may acquire assets that could be candidates for acquisition by the Partnership, potentially after operational or commercial improvement or further development.

At February 25, 2011, our interests in the Partnership consist of the following:

•  
a 2% general partner interest, which we hold through our 100% ownership interest in Targa Resources GP LLC, the general partner of the Partnership (the ”General Partner”);

•  
all of the outstanding IDRs; and

•  
11,645,659 of the 84,756,009 outstanding common units of the Partnership, representing a 13.7% limited partnership interest.

Our cash flows are generated from the cash distributions we receive from the Partnership. The Partnership is required to distribute all available cash at the end of each quarter after establishing reserves to provide for the proper conduct of its business or to provide for future distributions. Our ownership of the general partner interest entitles us to receive:

•  
2% of all cash distributed in respect for that quarter.

Our ownership in respect to the IDR’s of the Partnership that we hold, entitles us to receive:
 
•  
13% of all cash distributed in a quarter after $0.3881 has been distributed in respect of each common unit of the Partnership for that quarter;

•  
23% of all cash distributed in a quarter after $0.4219 has been distributed in respect of each common unit of the Partnership for that quarter; and

•  
48% of all cash distributed in a quarter after $0.50625 has been distributed in respect of each common unit of the Partnership for that quarter.

Because we control the General Partner, under generally accepted accounting principles we must reflect our ownership interest in the Partnership on a consolidated basis. Accordingly, our financial results are combined with the Partnership’s financial results in our consolidated financial statements even though the distribution or transfer of Partnership assets are limited by the terms of its partnership agreement, as well as restrictive covenants in the Partnership’s lending agreements. The limited partner interests in the Partnership not owned by controlling affiliates of us are reflected in our results of operations as net income attributable to non-controlling interests. Throughout this report we make a distinction where relevant between financial results of the Partnership versus those of us as a standalone parent.

 
Business of Targa Resources Partners LP

Overview

The Partnership is a leading provider of midstream natural gas and NGL services in the United States that we formed on October 26, 2006 to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. The Partnership is engaged in the business of gathering, compressing, treating, processing and selling natural gas and storing, fractionating, treating, transporting and selling NGLs and NGL products. The Partnership operates in two primary divisions: (i) Natural Gas Gathering and Processing, consisting of two segments—(a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) NGL Logistics and Marketing consisting of two segments—(a) Logistics Assets and (b) Marketing and Distribution.

Since the beginning of 2007, the Partnership has completed six acquisitions from us with an aggregate purchase price of approximately $3.1 billion. The acquisitions from us are as follows:

•  
In February 2007, in connection with its initial public offering, the Partnership acquired approximately 3,950 miles of integrated gathering pipelines that gather and compress natural gas received from receipt points in the Fort Worth Basin/Bend Arch in North Texas, two natural gas processing plants and a fractionator. These assets, together with the business conducted thereby, are collectively referred to as the “North Texas System.”

•  
In October 2007, the Partnership acquired natural gas gathering, processing and treating assets in the Permian Basin of West Texas and in Southwest Louisiana. The West Texas assets, together with the business conducted thereby, are collectively referred to as “SAOU” and the Southwest Louisiana assets, together with the business conducted thereby, are collectively referred to as “LOU.”

•  
In September 2009, the Partnership acquired our NGL business consisting of fractionation facilities, storage and terminalling facilities, low sulfur natural gasoline treating facilities, pipeline transportation and distribution assets, propane storage, truck terminals and NGL transport assets. These assets, together with the businesses conducted thereby, are collectively referred to as the NGL Logistics and Marketing division or the “Downstream Business.”

•  
In April 2010, the Partnership acquired a natural gas straddle business consisting of the business and operations involving the Barracuda, Lowry and Stingray plants, including the Pelican, Seahawk and Cameron gas gathering pipeline systems, and the interests in the business and operations  of the Bluewater, Sea Robin, Calumet, N. Terrebonne, Toca and Yscloskey plants. These assets, together with the business conducted thereby, are collectively referred to as the “Coastal Straddles.” The Partnership also acquired certain natural gas gathering and processing systems, processing plants and related assets including the Sand Hills processing plant and gathering system, Monahans gathering system, Puckett gathering system, a 40% ownership interest in the West Seminole gathering system and a compressor overhaul facility. These assets, together with the business conducted thereby, are collectively referred to as the “Permian Business.”

•  
In August 2010, the Partnership acquired a 63% ownership interest in Versado Gas Processors, L.L.C. (“Versado”), which conducts a natural gas gathering and processing business in New Mexico consisting of the business and operations involving the Eunice, Monument and Saunders gathering and processing systems, processing plants and related assets. These assets, together with the business conducted thereby, are collectively referred to as “Versado.”

•  
In September, 2010, the Partnership acquired from us our 77% ownership interest in Venice Energy Services Company, L.L.C. (“VESCO”), a joint venture in which Enterprise Gas Processing, LLC and ONEOK VESCO Holdings, L.L.C. own the remaining ownership interests. VESCO owns and operates a natural gas gathering and processing business in Louisiana consisting of a coastal straddle plant and the business and operations of Venice Gathering System, L.L.C., a wholly owned subsidiary of VESCO that owns and operates an offshore gathering system and related assets (collectively, “VESCO”).

With the above acquisitions, the Partnership has acquired all of our operating assets. In addition, the Partnership has successfully completed both large and small organic growth projects associated with its existing assets and expects to continue to do so in the future. These projects, some of which occurred before the Partnership acquired its various businesses from us, have involved growth capital expenditures of approximately $312.9 million since 2005 and include:

•  
Low sulfur natural gasoline project: In July 2007, the Partnership completed construction of a natural gasoline hydrotreater (the “LSNG” facility) at Mont Belvieu, Texas that removes sulfur from natural gasoline, allowing customers to meet new, more stringent environmental standards. The facility has a capacity of 30 MBbls/d and is supported by fee-based contracts with Marathon Petroleum Company LLC and Koch Supply and Trading LP that have certain guaranteed volume commitments or provisions for deficiency payments. The Partnership made capital expenditures of $39.5 million to convert idle equipment at Mont Belvieu into the LSNG Facility.

•  
Operations Improvement and Efficiency Enhancement: The Partnership has historically focused on ways to improve margins and reduce operating expenses by improving its operations. Examples include energy saving initiatives such as building cogeneration capacity to self-generate electricity for the Partnership’s facilities at Mont Belvieu, installing electric compression in North Texas and Versado to reduce fuel costs, emissions and operating costs and bringing compression overhaul in-house to improve quality, turnaround time and costs.

•  
Opportunistic Commercial Development Activities: The Partnership has used the extensive footprint of its asset base to identify and pursue projects that generate strong returns on invested capital. Examples include installing a new interconnect pipeline to the Kinder Morgan Rancho line at SAOU, developing the Winona wholesale propane terminal in Arizona, restarting the Easton Storage Facility at LOU and installing additional equipment to increase ethane recoveries at the Partnership’s Lowry straddle plant.

•  
Other Enhancements: The Partnership also has completed a number of smaller acquisitions and projects that have enhanced its existing asset base and that can provide attractive investment returns. Examples include the purchase of existing pipelines that expand beyond its existing asset base; installation of pipeline interconnects to its gathering systems and consolidation of interests in joint ventures.

The Partnership believes these projects have been successful in terms of return on investment. Because the Partnership’s assets are not easily duplicated and are located in active producing areas and near key NGL markets and logistics centers, we expect that the Partnership will continue to focus on attractive investment opportunities associated with its existing asset base.

 
Partnership Growth Drivers

We believe the Partnership’s near-term growth will be driven both by significant recently completed or pending projects as well as strong supply and demand fundamentals for its existing businesses. Over the longer-term, we expect the Partnership’s growth will be driven by natural gas shale opportunities, which could lead to growth in both the Partnership’s Gathering and Processing division and the Downstream Business, organic growth projects and potential strategic and other acquisitions related to its existing businesses.

Organic growth projects. We expect the Partnership’s near-term growth to be driven by a number of significant projects scheduled for completion in 2011 that are supported by long-term, fee-based contracts. We believe that organic growth projects, such as the ones listed below, often generate higher returns on investment than those available from third-party acquisitions. Organic projects in process include:


Expansion Programs at Mount Belvieu

•  
Cedar Bayou Fractionator expansion project: The Partnership is currently constructing approximately 78 MBbl/d of additional fractionation capacity at the Partnership’s 88% owned Cedar Bayou Fractionator (“CBF”) in Mont Belvieu for an estimated gross cost of $78 million. The fractionation expansion is expected to be in-service in the second quarter of 2011. This expansion is supported with 10 year fee-based contracts with ONEOK Hydrocarbons, L.P., Questar Gas Management Company and Majestic Energy Services, LLC that have certain guaranteed volume commitments or provisions for deficiency payments.

•  
Benzene treating project: A new treater is under construction which will operate in conjunction with the Partnership’s existing LSNG facility at Mont Belvieu and is designed to reduce benzene content of natural gasoline to meet new, more stringent environmental standards. The treater has an estimated gross cost of approximately $33 million. The treater is anticipated to be in service in the fourth quarter of 2011 and is supported by a fee-based contract with Marathon Petroleum Company LLC that has certain guaranteed volume commitments or provisions for deficiency payments.

•  
Gulf Coast Fractionators expansion project: The Partnership has announced plans by Gulf Coast Fractionators (“GCF”), a partnership with ConocoPhillips and Devon Energy Corporation in which the Partnership owns a 38.8% interest, to expand the capacity of its NGL fractionation facility in Mont Belvieu by 43 MBbl/d for an estimated gross cost of $75 million (our net cost is estimated to be approximately $29 million). ConocoPhillips, as the operator, will manage the expansion project. The expansion is expected to be operational during the second quarter of 2012, subject to regulatory approvals.

SAOU Expansion Program

•  
The Partnership has announced a $30 million capital expenditure program to expand gathering and processing capability over the next 18 months in response to strong volume growth and new well connects associated with producer activity particularly in the Wolfberry play as discussed below under “— Strong supply and demand fundamentals for the Partnership’s existing businesses.” This growth investment program includes new compression facilities and pipelines as well as expenditures to restart the 25 MMcf/d Conger processing plant anticipated to be completed by early 2011.

North Texas Expansion Program

•  
The board of directors of the general partner has approved approximately $40 million of capital expenditures to expand the gathering and processing capability of the North Texas System with certain provisions of the approved expenditures subject to finalization of ongoing customer commercial agreements. The expansion program is a response to strong volume growth and new well connects associated with producer activity in “oilier” portions of the Barnett Shale natural gas play, especially in portions of Southern Montague and Northern Wise County as discussed below under “— Strong supply and demand fundamentals for our existing businesses.” The scope of the full expansion includes a major pipeline to increase residue takeaway capacity, gathering system expansions, compression equipment and other work. Certain pieces of the expansion are underway. If commercial agreements were to be consummated in the first half of 2011, we would expect most capital investment to be completed by early 2012.

Strong supply and demand fundamentals for the Partnership’s existing businesses.

We believe that the current strength of oil, condensate and NGL prices and of forecast prices for these energy commodities has caused producers in and around the Partnership’s natural gas gathering and processing areas of operation to focus their drilling programs on regions rich in these forms of hydrocarbons. Liquids rich gas is prevalent from the Wolfberry and Canyon Sands plays, which are accessible by SAOU, the Wolfberry and Bone Springs plays, which are accessible by the Sand Hills plant and gathering system, and from “oilier” portions of the Barnett Shale natural gas play, especially portions of Montague, Cooke, Clay and Wise counties, which are accessible by the North Texas System. The Wolfberry, Canyon Sands, and Bone Springs plays are oil plays with associated gas containing high liquids content ranging from approximately 7.0 to 9.5 gal/Mcf. By comparison, the liquids content of the gas from the liquids rich portion of the Eagle Ford Shale natural gas play is expected to average about 4 gal/Mcf. The Partnership has observed increased drilling permits and higher rig counts in these areas and expects these activities to result in higher inlet volumes over the next several years.

Producer activity in areas rich in oil, condensate and NGLs is currently generating high demand for the Partnership’s fractionation services at the Mont Belvieu market hub. As a result, fractionation volumes have recently increased to near existing capacity. Until additional fractionation capacity comes on-line in 2011, there will be limited incremental supply of fractionation services in the area. These strong supply and demand fundamentals have resulted in long-term, “take-or-pay” contracts for existing capacity and support the construction of new essentially fully committed fractionation capacity, such as the Partnership’s CBF and GCF expansion projects. The Partnership is continuing to see rates for fractionation services increase.  Existing fractionation customers are renewing contracts at market rates that are, in most cases, substantially higher than expiring rates for extended terms of up to ten years and with reservation fees that are paid even if customer volumes are not fractionated to ensure access to fractionation services. A portion of the recent and future expected increases in cash flow for the Partnership’s fractionation business is related to high utilization and rollover of existing contracts to higher rates. The higher volumes of fractionated NGLs should also result in increased demand for other related fee-based services provided by the Partnership’s Downstream Business.

 
Casinghead gas and liquids rich shale opportunities and similar oil and gas resource plays.

The Partnership is actively pursuing natural gas gathering and processing and NGL fractionation opportunities associated with many of the active, liquids-rich natural gas and other active oil and gas resource shale plays, such as the Permian, Wolfberry, and Bone Springs plays and certain regions of the Eagle Ford Shale. We believe that the Partnership’s leadership position in the NGL Logistics and Marketing business, which includes the Partnership’s fractionation services, provides the Partnership with a competitive advantage relative to other gathering and processing companies without these capabilities. While we believe that the expected growth in the supply of liquids-rich gas from these plays will likely require the construction of (i) additional fractionation capacity, (ii) additional pipelines to transport the NGLs to and from major fractionation centers and (iii) additional natural gas gathering and processing facilities, the Partnership’s active involvement in multiple potential projects does not guarantee that it will be involved with any such capacity expansions.
 
Potential third-party acquisitions related to the Partnership’s existing businesses. While the Partnership’s recent growth has been partially driven by the implementation of a focused drop drown strategy, our management team also has a record of successful third party acquisitions. Since our formation, our strategy has included approximately $3 billion in third party acquisitions and growth capital expenditures. This track record includes:

•  
The 2004 acquisition of SAOU and LOU from ConocoPhillips Company for $248 million;

•  
The 2004 acquisition of a 40% interest in Bridgeline Holdings, LP for $101 million from the Enron Corporation bankruptcy estate. Chevron Corporation, the other owner, exercised its rights under the partnership agreement to purchase the 40% stake from us for $117 million in 2005;

•  
The 2005 acquisition of Dynegy Midstream Services, Limited Partnership from Dynegy, Inc. for
 
$2.4 billion; and

•  
The 2008 acquisition of Chevron Corporation’s 53.9% interest in VESCO.

We expect that third-party acquisitions will continue to be a significant focus of the Partnership’s growth strategy.


Competitive Strengths and Strategies

We believe the Partnership is well positioned to execute its business strategies due to the following competitive strengths:

Leading fractionation position.

The Partnership is one of the largest fractionators of NGLs in the Gulf Coast. Its primary fractionation assets are located in Mont Belvieu, Texas and Lake Charles, Louisiana, which are key market centers for NGLs and are located at the intersection of NGL infrastructure including mixed NGL supply pipelines, storage, takeaway pipelines and other transportation infrastructure. The Partnership’s assets are also located near and connected to key consumers of NGL products including the petrochemical and industrial markets. The location and interconnectivity of the assets are not easily replicated, and the Partnership has sufficient additional capability to expand their capacity. Our management has extensive experience in operating these assets and in permitting and building new midstream assets.

Strategically located gathering and processing asset base.

The Partnership’s gathering and processing businesses are predominantly located in active and growth oriented oil and gas producing basins. Activity in the Canyon Sands, Bone Springs, Wolfberry, and Barnett Shale plays is driven by the economics of current favorable oil, condensate and NGL prices and the high condensate and NGL content of the natural gas or associated natural gas streams. Increased drilling and production activities in these areas would likely increase the volumes of natural gas available to the Partnership’s gathering and processing systems.

Comprehensive package of midstream services.

The Partnership provides a comprehensive package of services to natural gas producers, including natural gas gathering, compression, treating, processing and selling natural gas and storing, fractionating, treating, transporting and selling NGLs and NGL products. These services are essential to gather, process and treat wellhead gas to meet pipeline standards and to extract NGLs for sale into petrochemical, industrial and commercial markets. We believe the Partnership’s ability to provide these integrated services provides an advantage in competing for new supplies of natural gas because the Partnership can provide substantially all of the services producers, marketers and others require for moving natural gas and NGLs from wellhead to market on a cost-effective basis. Additionally, due to the high cost of replicating assets in key strategic positions, the difficulty of permitting and constructing new midstream assets and the difficulty of developing the expertise necessary to operate them, the barriers to enter the midstream natural gas sector on a scale similar to the Partnership’s are reasonably high.

High quality and efficient assets.

The Partnership’s gathering and processing systems and logistics assets consist of high-quality, well-maintained facilities, resulting in low-cost, efficient operations. Advanced technologies have been implemented for processing plants (primarily cryogenic units utilizing centralized control systems), measurement (essentially all electronic and electronically linked to a central data base) and operations and maintenance to manage work orders and implement preventative maintenance schedules (computerized maintenance management systems). These applications have allowed proactive management of the Partnership’s operations resulting in lower costs and minimal downtime. The Partnership has established a reputation in the midstream industry as a reliable and cost-effective supplier of services to its customers and has a track record of safe and efficient operation of its facilities. The Partnership intends to continue to pursue new contracts, cost-efficiencies and operating improvements of its assets. Such improvements in the past have included new production and acreage commitments, reducing fuel gas and flare volumes and improving facility capacity and NGL recoveries. The Partnership will also continue to optimize existing plant assets to improve and maximize capacity and throughput.
 
Large, diverse business mix with favorable contracts.

The Partnership maintains gathering and processing positions in strategic oil and gas producing areas across multiple oil and gas basins and provides services under attractive contract terms to a diverse mix of customers across its areas of operations. Consequently, the Partnership is not dependent on any one oil and gas basin or customer. The gathering and processing contract portfolio has attractive rate and term characteristics. The Partnership’s NGL Logistics and Marketing assets are typically located near key market hubs and near important NGL customers. They also serve must-run portions of the natural gas value chain, are primarily fee-based and have a diverse mix of customers. The logistics contract portfolio, largely fee-based, has attractive rate and term characteristics. Given the higher rates for logistics assets contracts that are being renewed (largely based on replacement cost economics), the new projects underway, the long-term nature of many of the renewed and new contracts and continuing strong supply and demand fundamentals for this business, we expect an increasing percentage of the Partnership’s cash flows to be fee-based.

Financial flexibility.

The Partnership has historically maintained strong financial metrics relative to its peer group, with leverage and distribution coverage ratios consistently above the peer group median. The Partnership also reduces the impact of commodity price volatility by hedging the commodity price risk associated with a portion of its expected natural gas, NGL and condensate equity volumes. Maintaining appropriate leverage and distribution coverage levels and mitigating commodity price volatility allow the Partnership to be flexible in its growth strategy and enable it to pursue strategic acquisitions and large growth projects.

Experienced and long-term focused management team.

The executive management team that formed Targa in 2004 and continues to manage TRI Resources Inc. today possesses over 200 years of combined experience working in the midstream natural gas and energy business. Other officers and key operational, commercial and financial employees provide depth of experience in the industry and with our assets and businesses.

Attractive Partnership Cash Flow Characteristics

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

The Partnership has hedged the commodity price risk associated with a portion of its expected natural gas, NGL and condensate equity volumes through 2014 by entering into financially settled derivative transactions including swaps and purchased puts (or floors). The primary purpose of its commodity risk management activities is to hedge the Partnership’s exposure to price risk and to mitigate the impact of fluctuations in commodity prices on cash flow. The Partnership has intentionally tailored its hedges to approximate specific NGL products and to approximate its actual NGL and residue natural gas delivery points. The Partnership intends to continue to manage its exposure to commodity prices in the future by entering into similar hedge transactions as market conditions permit.

The Partnership also monitors its inventory levels with a view of mitigating losses related to downward price exposure.

The Partnership’s annual maintenance capital expenditures have averaged approximately $54.0 million per year over the last three years. We believe that the Partnership’s assets are well maintained and anticipate that a similar level of capital expenditures will be sufficient for it to continue to operate these assets in a prudent and cost-effective manner.

Asset Base Well-Positioned for Organic Growth

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

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

We have used the Partnership as a growth vehicle to pursue the acquisition and expansion of midstream natural gas, NGL and other complementary energy businesses and assets as evidenced by its acquisition of businesses from us. However, we are not prohibited from competing with the Partnership and routinely evaluate acquisitions that do not involve the Partnership. In addition, through its relationship with us, the Partnership has access to a significant pool of management talent, strong commercial relationships throughout the energy industry and access to our broad operational, commercial, technical, risk management, and administrative functions.
 
 
As of February 14, 2011, we and our management have a significant interest in the Partnership through our combined 14.2% limited partner interest and our 2% general partnership interest in the Partnership. In addition, we own incentive distribution rights that entitle us to receive an increasing percentage of quarterly distributions of the Partnership’s available cash from its operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. We are party to an Omnibus Agreement with the Partnership that governs our relationship regarding certain reimbursement and indemnification matters. See “Item 13. Certain Relationships and Related Transactions, and Director Independence-Omnibus Agreement.” We employ 1,020 people who support primarily the Partnership’s operations. See “-Employees.” We allocate the cost of these employees to the Partnership in accordance with the Omnibus Agreement. Following the conveyance of all of our remaining operating assets to the Partnership in September 2010, substantially all of our general and administrative costs have been and will continue to be allocated to the Partnership, other than our direct costs of being a separate public reporting company.
 
The Partnership’s Challenges

The Partnership faces a number of challenges in implementing its business strategy. For example:

•  
The Partnership has a substantial amount of indebtedness which may adversely affect its financial position.

•  
The Partnership’s cash flow is affected by supply and demand for oil, natural gas and NGL products and by natural gas and NGL prices, and decreases in these prices could adversely affect its results of operations and financial condition.

•  
The Partnership’s long-term success depends on its ability to obtain new sources of supplies of natural gas and NGLs, which depends on certain factors beyond its control. Any decrease in supplies of natural gas or NGLs could adversely affect the Partnership’s business and operating results.

•  
If the Partnership does not make acquisitions or investments in new assets on economically acceptable terms or efficiently and effectively integrate new assets, its results of operations and financial condition could be adversely affected.

•  
The Partnership is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect its results of operations and financial condition.

•  
The Partnership’s growth strategy requires access to new capital. Tightened capital markets or increased competition for investment opportunities could impair its ability to grow.

•  
The Partnership’s hedging activities may not be effective in reducing the variability of its cash flows and may, in certain circumstances, increase the variability of its cash flows.

•  
The Partnership’s industry is highly competitive, and increased competitive pressure could adversely affect the Partnership’s business and operating results.

For a further discussion of these and other challenges that we and the Partnership face, please read “Item 1A. Risk Factors.”

Partnership Business Operations

The operations of the Partnership are reported in two divisions: (i) Natural Gas Gathering and Processing, consisting of two segments—(a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) NGL Logistics and Marketing, consisting of two segments—(a) Logistics Assets and (b) Marketing and Distribution.

Natural Gas Gathering and Processing Division

The Partnership’s Natural Gas Gathering and Processing Division consists of gathering, compressing, dehydrating, treating, conditioning, processing, transporting and marketing natural gas. The gathering of natural gas consists of aggregating natural gas produced from various wells through small diameter gathering lines to processing plants. Natural gas has a widely varying composition, depending on the field, the formation and the reservoir from which it is produced. The processing of natural gas consists of the extraction of imbedded NGLs and the removal of water vapor and other contaminants to form (i) a stream of marketable natural gas, commonly referred to as residue gas, and (ii) a stream of mixed NGLs, commonly referred to as “Mixed NGLs” or “Y-grade.” Once processed, the residue gas is transported to markets through pipelines that are either owned by the gatherers or processors or third parties. End users of residue gas include large commercial and industrial customers, as well as natural gas and electric utilities serving individual consumers. The Partnership sells its residue gas either directly to such end users or to marketers into intrastate or interstate pipelines, which are typically located in close proximity or with ready access to its facilities.

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

We believe the Partnership’s extensive asset base and scope of operations in the regions in which the Partnership operates provide the Partnership with significant opportunities to add both new and existing natural gas production to its systems. We believe the Partnership’s size and scope gives the Partnership a strong competitive position by placing it in close proximity to a large number of existing and new natural gas producing wells in its areas of operations, allowing the Partnership to generate economies of scale and to provide its customers with access to its existing facilities and to multiple end-use markets and market hubs. Additionally, we believe the Partnership’s ability to serve its customers’ needs across the natural gas and NGL value chain further augments the Partnership’s ability to attract new customers.

 
Field Gathering and Processing Segment

The Field Gathering and Processing segment gathers and processes natural gas from the Permian Basin in West Texas and Southeast New Mexico and the Fort Worth Basin, including the Barnett Shale, in North Texas. The natural gas processed in this segment is supplied through its gathering systems which, in aggregate, consist of approximately 10,100 miles of natural gas pipelines. The segment’s processing plants include nine owned and operated facilities. For the year ended December 31, 2010, the Partnership processed an average of approximately 588 MMcf/d of natural gas and produced an average of approximately 71 MBbl/d of NGLs.
We believe the Partnership is well positioned as a gatherer and processor in the Permian and Fort Worth Basins. The Partnership has broad geographic scope, covering portions of 40 counties and approximately 18,100 square miles across these basins. We believe proximity to production and development provides the Partnership with a competitive advantage in capturing new supplies of natural gas because of the Partnership’s competitive costs to connect new wells and to process additional natural gas in its existing processing plants. Additionally, because the Partnership operates all of its plants in these regions, the Partnership is often able to redirect natural gas among two or more of its processing plants, allowing it to optimize processing efficiency and further improve the profitability of its operations.

The Field Gathering and Processing segment’s operations consist of the Permian Business, Versado, SAOU and the North Texas System, each as described below.

Permian Business. The Permian Business consists of the Sand Hills gathering and processing system and the West Seminole and Puckett gathering systems. These systems consist of approximately 1,300 miles of natural gas gathering pipelines. These gathering systems are low-pressure gathering systems with significant compression assets. The Sand Hills refrigerated cryogenic processing plant has a gross processing capacity of 150 MMcf/d and residue gas connections to pipelines owned by affiliates of Enterprise Products Partners L.P., ONEOK, Inc. and El Paso Corporation (“El Paso”).

Versado. Versado consists of the Saunders, Eunice and Monument gas processing plants and related gathering systems in Southeastern New Mexico. The gathering systems consist of approximately 3,200 miles of natural gas gathering pipelines. The Saunders, Eunice and Monument refrigerated cryogenic processing plants have aggregate processing capacity of 280 MMcf/d (176 MMcf/d, net to the Partnership’s ownership interest). These plants have residue gas connections to pipelines owned by affiliates of El Paso, MidAmerican Energy Company and Kinder Morgan Energy Partners, L.P. The Partnership’s ownership in the Versado System is held through Versado Gas Processors, L.L.C., a joint venture that is 63% owned by the Partnership and 37% owned by Chevron U.S.A. Inc.

SAOU. Covering portions of 10 counties and approximately 4,000 square miles in West Texas, SAOU includes approximately 1,500 miles of pipelines in the Permian Basin that gather natural gas to the Mertzon and Sterling processing plants. SAOU is connected to numerous producing wells and central delivery points. SAOU has approximately 1,000 miles of low-pressure gathering systems and approximately 500 miles of high-pressure gathering pipelines to deliver the natural gas to the Partnership’s processing plants. The gathering system has numerous compressor stations to inject low-pressure gas into the high-pressure pipelines. SAOU’s processing facilities include 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. The Partnership is in the process of restarting the Conger plant and anticipates completion by early 2011 and for it to provide for rapidly increasing volumes in SAOU.

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

The Chico Gathering System consists of approximately 2,000 miles of primarily low-pressure gathering pipelines. Wellhead natural gas is either gathered for the Chico plant located in Wise County, Texas, and then compressed for processing, or it is compressed in the field at numerous compressor stations and then moved via one of several high-pressure gathering pipelines to the Chico plant. The Shackelford Gathering System consists of approximately 2,100 miles of intermediate-pressure gathering pipelines which gather wellhead natural gas largely for the Shackelford plant in Albany, Texas. Natural gas gathered from the northern and eastern portions of the Shackelford Gathering System is typically compressed in the field at numerous compressor stations and then transported to the Chico plant for processing.
 
 
The following table lists the Field Gathering and Processing segment’s natural gas processing plants and related volumes for the year ended December 31, 2010:
 
 
 
 
 
 
 
 
Gross
 
Gross Plant
 
 
 
 
 
 
 
 
 
 
 
 
 
Processing
 
 Natural Gas
 
 
 
 
 
 
 
 
 
 
 
 
 
Capacity
 
Inlet Throughput
 
Gross NGL
 
Process
 
Operated/
Facility
 
% Owned
 
Location
 
(MMcf/d)
 
Volume (MMcf/d)
 
Production
 
Type (4)
 
Non-Operated
Permian Business
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sand Hills
 
100 
 
Crane, TX
 
150.0 
 
116.5 
 
14.4 
 
Cryo
 
Operated
 
Other Permian (1)
 
 
 
 
 
 
 
12.3 
 
0.4 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Versado
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Saunders (2)
 
63 
 
Lea, NM
 
70.0 
 
 
 
 
 
Cryo
 
Operated
 
Eunice (2)
 
63 
 
Lea, NM
 
120.0 
 
 
 
 
 
Cryo
 
Operated
 
Monument (2)
 
63 
 
Lea, NM
 
90.0 
 
 
 
 
 
Cryo
 
Operated
 
 
 
 
Area Total
 
280.0 
 
178.7 
 
20.4 
 
 
 
 
SAOU
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mertzon
 
100 
 
Irion, TX
 
48.0 
 
 
 
 
 
Cryo
 
Operated
 
Sterling
 
100 
 
Sterling, TX
 
62.0 
 
 
 
 
 
Cryo
 
Operated
 
Conger (3)
 
100 
 
Sterling, TX
 
25.0 
 
 
 
 
 
Cryo
 
Operated
 
 
 
 
 
Area Total
 
135.0 
 
99.8 
 
20.7 
 
 
 
 
North Texas System
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Chico (4)
 
100 
 
Wise, TX
 
265.0 
 
 
 
 
 
Cryo
 
Operated
 
Shackelford
 
100 
 
Shackelford, TX
 
13.0 
 
 
 
 
 
Cryo
 
Operated
 
 
 
 
Area Total
 
278.0 
 
180.4 
 
15.3 
 
 
 
 
 
 
 
Segment System Total
 
843.0 
 
587.7 
 
71.2 
 
 
 
 
 
_________
(1)  
 Other Permian includes throughput other than plant inlet, primarily from compressor stations.
(2)  
These plants are part of our Versado joint venture, of which we own a 63%, capacity and volumes represent 100% of ownership interest.
(3)  
The Partnership is in the process of restarting the Conger plant, which we anticipate occurring in early 2011, to provide for rapidly increasing volumes in SAOU.
(4)  
The Chico plant has fractionation capacity of approximately 15 MBbl/d.
(5)  
Cryo—Cryogenic Processing.

Coastal Gathering and Processing Segment

The Partnership’s Coastal Gathering and Processing segment assets are located in the onshore region of the Louisiana Gulf Coast and the Gulf of Mexico. With the strategic location of its assets in Louisiana, the Partnership has access to the Henry Hub, the largest natural gas hub in the U.S., and a substantial NGL distribution system with access to markets throughout Louisiana and the southeast U.S. The Coastal Gathering and Processing segment’s assets consist of the Coastal Straddles, VESCO and LOU, each as described below. For the year ended December 31, 2010, the Partnership processed an average of approximately 1,680 MMcf/d of plant natural gas inlet and produced an average of approximately 50 MBbl/d of NGLs.

Coastal Straddles. Coastal Straddles consists of three wholly owned and operated gas processing plants and six partially owned plants, some of which are operated by the Partnership. The plants are generally situated on mainline natural gas pipelines near the coastline and process volumes of natural gas collected from multiple offshore gathering systems and pipelines throughout the Gulf of Mexico. Coastal Straddles also has ownership in three offshore gathering systems that are operated by the Partnership. The Pelican and Seahawk pipeline systems are non-FERC regulated gathering systems that have a combined length of approximately 175 miles and a combined capacity of approximately 230 MMcf per day. These systems gather natural gas from shallow waters of the central Gulf of Mexico and supply a portion of the natural gas delivered to the Barracuda and Lowry processing facilities.

Coastal Straddles process natural gas produced from shallow water central and western Gulf of Mexico natural gas wells and from deep shelf and deepwater Gulf of Mexico production via connections to third-party pipelines or through pipelines owned by the Partnership. Coastal Straddles has access to markets across the U.S. through the interstate natural gas pipelines to which it is interconnected. Through the Partnership’s 77% ownership interest in VESCO, the Partnership operates the Venice Gathering System (“VGS”), an offshore gathering system regulated as an interstate pipeline by the Federal Energy Regulatory Commission (“FERC”). VGS is approximately 150 miles in length and has a nominal capacity of 320 MMcf per day. VGS gathers natural gas from the shallow waters of eastern Gulf of Mexico and supplies a portion of the natural gas to the Venice gas plant.

LOU. LOU consists of approximately 850 miles of gathering system pipelines, covering approximately 3,800 square miles in Southwest Louisiana. The gathering 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. The processing facilities include 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.
  
 
The following table lists the Coastal Gathering and Processing segment’s natural gas processing plants for the year ended December 31, 2010:

 
 
 
 
 
 
 
Approximate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gross
 
Gross Plant
 
 
 
 
 
 
 
 
 
 
 
 
 
Processing
 
Natural Gas
 
 
 
 
 
 
 
 
 
 
 
 
 
Capacity
 
Inlet Throughput
 
Gross NGL
 
Process
 
Operated/
Facility
 
% Owned
 
Location
 
(MMcf/d)
 
Volume (MMcf/d)
 
Production
 
Type (4)
 
Non-operated
Coastal Straddles (1)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Barracuda
 
100 
 
Cameron, LA
 
 190 
 
 138.0 
 
 3.3 
 
Cryo
 
Operated
 
Lowry
 
100 
 
Cameron, LA
 
 265 
 
 110.8 
 
 2.8 
 
Cryo
 
Operated
 
Stingray
 
100 
 
Cameron, LA
 
 300 
 
 269.3 
 
 4.7 
 
RA
 
Operated
 
Calumet (2)
 
32.4 
 
St. Mary, LA
 
 1,650 
 
 128.2 
 
 2.9 
 
RA
 
Non-operated
 
Yscloskey (2)
 
25.3 
 
St. Bernard, LA
 
 1,850 
 
 290.3 
 
 2.1 
 
RA
 
Operated
 
Bluewater (2)
 
21.8 
 
Acadia, LA
 
 425 
 
 - 
 
 - 
 
Cryo
 
Non-operated
 
Terrebonne (2)
 
4.8 
 
Terrebonne, LA
 
 950 
 
 22.4 
 
 0.9 
 
RA
 
Non-operated
 
Toca (2)
 
10.7 
 
St. Bernard, LA
 
 1,150 
 
 50.8 
 
 1.3 
 
Cryo/RA
 
Non-operated
 
Iowa
 
100 
 
Jeff Davis, LA
 
 500 
 
 - 
 
 - 
 
Cryo
 
Operated
 
Sea Robin
 
0.8 
 
Vermillion, LA
 
 700 
 
 25.4 
 
 0.6 
 
Cryo
 
Non-operated
 
VESCO
 
76.8 
 
Plaquemines, LA
 
 750 
 
 427.3 
 
 23.2 
 
Cryo
 
Operated
 
Other
 
 
 
 
 
 
 
 33.2 
 
 1.1 
 
 
 
 
 
 
 
 
 
Area Total
 
 8,730 
 
 1,495.7 
 
 42.9 
 
 
 
 
LOU
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gillis (3)
 
100 
 
Calcasieu, LA
 
180 
 
 
 
 
 
Cryo
 
 
 
Acadia
 
100 
 
Acadia, LA
 
80 
 
 
 
 
 
Cryo
 
 
 
 
 
 
 
Area Total
 
260 
 
 184.6 
 
 7.2 
 
 
 
 
 
 
Consolidated System Total
 
 8,990 
 
 1,680.3 
 
 50.1 
 
 
 
 
 
_________
(1) Coastal Straddles also includes three offshore gathering systems which have a combined length of approximately 325 miles.
(2) Our ownership is adjustable and subject to annual redetermination.
(3) The Gillis plant has fractionation capacity of approximately 13 MBbl/d.
(4) Cryo—Cryogenic Processing; RA—Refrigerated Absorption Processing.

NGL Logistics and Marketing Division

The NGL Logistics and Marketing division is also referred to as the Downstream Business. It includes the activities necessary to convert mixed NGLs into NGL products, market the NGL products and provides certain value added services such as the fractionation, storage, terminalling, transportation, distribution and marketing of NGLs, as well as certain natural gas supply and marketing activities in support of our other businesses. Through fractionation, mixed NGLs are separated into its component parts (ethane, propane, butanes and natural gasoline). These component parts are delivered to end-users through pipelines, barges, trucks and rail cars. End-users of component NGLs include petrochemical and refining companies and propane markets for heating, cooking or crop drying applications. Retail distributors often sell to end-use propane customers.

Logistics Assets Segment

This segment uses its platform of integrated assets to fractionate, store, treat and transport NGLs typically under fee-based and margin-based arrangements. For NGLs to be used by refineries, petrochemical manufacturers, propane distributors and other industrial end-users, they must be fractionated into their component products and delivered to various points throughout the U.S. The Partnership’s logistics 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.

Fractionation. After being extracted in the field, mixed NGLs, sometimes referred to as “Y-grade” or “raw NGL mix,” are typically transported to a centralized facility for fractionation where the mixed NGLs are separated into discrete NGL products: ethane, propane, butanes and natural gasoline. Mixed NGLs delivered from the Partnership’s Field and Coastal Gathering and Processing segments represent the largest source of volumes processed by the Partnership’s NGL fractionators.

The Partnership’s fractionation assets include ownership interests in three stand-alone fractionation facilities that are located on the Gulf Coast, two of which it operates, one at Mont Belvieu, Texas, and the other at Lake Charles, Louisiana.  It also has an equity investment in a third fractionator, GCF, also located at Mont Belvieu.  The Partnership is subject to a consent decree with the Federal Trade Commission, issued December 12, 1996, that, among other things, prevents it from participating in commercial decisions regarding rates paid by third parties for fractionation services at GCF. This restriction on the Partnership activity at GCF will terminate on December 12, 2016, twenty years after the date the consent order was issued. In addition to the three stand-alone facilities in the Logistics Assets segment, see the description of fractionation assets in the North Texas System and LOU in our Natural Gas Gathering and Processing division.
 
 
The majority of the Partnership’s NGL fractionation business is under fee-based arrangements. These fees are subject to adjustment for changes in certain fractionation expenses, including energy costs. The operating results of the Partnership’s NGL fractionation business are dependent upon the volume of mixed NGLs fractionated and the level of fractionation fees charged.

We believe that sufficient volumes of mixed NGLs will be available for fractionation in commercially viable quantities for the foreseeable future due to increases in NGL production expected from shale plays in areas of the U.S. that include North Texas, South Texas, Oklahoma and the Rockies and certain other basins accessed by pipelines to Mont Belvieu, as well as from continued production of NGLs in areas such as the Permian Basin, Mid-Continent, East Texas, South Louisiana and shelf and deepwater Gulf of Mexico. Dew point specifications implemented by individual pipelines and the policy statement enacted by FERC should result in volumes of mixed NGLs being available for fractionation because natural gas requires processing or conditioning to meet pipeline quality specifications. These requirements establish a base volume of mixed NGLs during periods when it might be otherwise uneconomical to process certain sources of natural gas. Furthermore, significant volumes of mixed NGLs are contractually committed to the Partnership’s NGL fractionation facilities.

Although competition for NGL fractionation services is primarily based on the fractionation fee, the ability of an NGL fractionator to obtain mixed NGLs and distribute NGL products is also an important competitive factor. This ability is a function of the existence of storage infrastructure and supply and market connectivity necessary to conduct such operations. We believe that the location, scope and capability of the Partnership’s logistics assets, including its transportation and distribution systems, give the Partnership access to both substantial sources of mixed NGLs and a large number of end-use markets.

The Partnership also has a natural gasoline hydrotreater at Mont Belvieu, Texas that removes sulfur from natural gasoline, allowing customers to meet new, more stringent environmental standards. The facility has a capacity of 30 MBbls/d and is supported by fee-based contracts with Marathon Petroleum Company LLC and Koch Supply and Trading LP that have certain guaranteed volume commitments or provisions for deficiency payments.

The following table details the Logistics Assets segment’s fractionation and treating facilities:
 
 
 
 
 
 
 
 
Gross Throughput for the
 
 
 
 
 
 
 
Year Ended
 
 
 
 
 
Maximum Gross Capacity
 
December 31, 2010
Facility
 
% Owned
 
(MBbls/d)
 
(MBbls/d)
Operated Facilities:
 
 
 
 
 
 
 
Lake Charles Fractionator (Lake Charles, LA)
 
100.0 
 
55.0 
 
39.1 
 
Cedar Bayou Fractionator (Mont Belvieu, TX) (1)
 
88.0 
 
215.0 
 
187.1 
 
LSNG Hydrotreater (Mont Belvieu, TX)
 
100.0 
 
30.0 
 
18.0 
Equity Fractionation Facilities (non-operated):
 
 
 
 
 
 
 
Gulf Coast Fractionator (Mont Belvieu, TX)
 
38.8 
 
109.0 
 
98.9 
 
_______
(1)  
Includes ownership through 88% interest in Downstream Energy Ventures Co, LLC.
 
Storage and Terminalling. In general, the Partnership’s storage assets provide warehousing of mixed NGLs, NGL products and petrochemical products in underground wells, which allows for the injection and withdrawal of such products at various times in order to meet demand cycles. Similarly, the Partnership’s terminalling operations provide the inbound/outbound logistics and warehousing of mixed NGLs, NGL products and petrochemical products in above-ground storage tanks. The Partnership’s underground storage and terminalling facilities serve single markets, such as propane, as well as multiple products and markets. For example, the Mont Belvieu and Galena Park facilities have extensive pipeline connections for mixed NGL supply and delivery of component NGLs. In addition, some of these facilities are connected to marine, rail and truck loading and unloading facilities that provide services and products to the Partnership’s customers. The Partnership provides long and short term storage and terminalling services and throughput capability to third party customers for a fee.

The Partnership owns or operates a total of 39 storage wells at its facilities with a net storage capacity of approximately 64.5 MMBbl, the usage of which may be limited by brine handling capacity, which is utilized to displace NGLs from storage.

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

The Partnership’s fractionation, storage and terminalling business is supported by approximately 800 miles of company-owned pipelines to transport mixed NGLs and specification products.

 
Logistics Assets NGL storage facilities at December 31, 2010:

 
 
NGL Storage Facilities
 
 
 
 
 
 
 
Number of
 
Gross Storage
 
Facility
 
% Owned
 
County/Parish, State
 
Permitted Wells
 
Capacity (MMBbl)
 
Hackberry Storage (Lake Charles)
 
100 
 
Cameron, LA
 
 12 
(1)
20.0 
 
Mont Belvieu Storage
 
100 
 
Chambers, TX
 
 20 
(2)
41.4 
 
Easton Storage
 
100 
 
Evangeline, LA
 
 1 
 
0.8 
 

_______
(1) Four of twelve owned wells leased to CITGO under long-term leases; one of twelve currently in service.
(2) The Partnership owns 20 wells and operates 6 wells owned by Chevron Phillips Chemical Company LLC.
 
Logistics Assets Terminal Facilities for the year ended December 31, 2010:

 
 
 
 
 
 
 
 
Throughput
 
Usable Storage
 
 
 
 
 
 
 
 
for 2010
 
Capacity
Facility
 
% Owned
 
County/Parish, State
 
Description
 
(Million gallons)
 
(MMBbl)
Galena Park Terminal (1)
 
100 
 
Harris, TX
 
NGL import/export terminal
 
916.8 
 
0.7 
Mont Belvieu Terminal (2)
 
100 
 
Chambers, TX
 
Transport and storage terminal
 
2,406.0 
 
48.9 
Hackberry Terminal
 
100 
 
Cameron, LA
 
Storage terminal
 
289.7 
 
17.8 
 
__________
(1) Volumes reflect total import and export across the dock/terminal.
(2) Volumes reflect total transport and terminal throughput volumes.

Marketing and Distribution Segment

The Marketing and Distribution segment transports, distributes and markets NGLs via terminals and transportation assets across the U.S. The Partnership owns or commercially manages terminal facilities in a number of states, including Texas, Louisiana, Arizona, Nevada, California, Florida, Alabama, Mississippi, Tennessee, Kentucky and New Jersey. The geographic diversity of the Partnership’s assets provides it direct access to many NGL customers as well as markets via trucks, barges, rail cars and open-access regulated NGL pipelines owned by third parties. The Marketing and Distribution segment consists of (i) NGL Distribution and Marketing, (ii) Wholesale Marketing, (iii) Refinery Services, and (iv) Commercial Transportation, each as described below.

NGL Distribution and Marketing. The Partnership markets its own NGL production and also purchases component NGL products from other NGL producers and marketers for resale. During the year ended December 31, 2010, the Partnership’s distribution and marketing services business sold an average of approximately 247 MBbl/d of NGLs.

The Partnership generally purchases mixed NGLs from producers at a monthly pricing index less applicable fractionation, transportation and marketing fees and resells these products to petrochemical manufacturers, refineries and other marketing and retail companies. This is primarily a physical settlement business in which the Partnership earns margins from purchasing and selling NGL products from producers under contract. The Partnership earns margins by purchasing and reselling NGL products in the spot and forward physical markets. To effectively serve its Distribution and Marketing customers, the Partnership contracts for and uses many of the assets included in its Logistics Assets segment. The Partnership also markets natural gas available from its Gathering and Processing segments, and purchases and resells natural gas in selected United States markets.

Wholesale Marketing. The Partnership’s wholesale propane marketing operations primarily sells propane and related logistics services to major multi-state retailers, independent retailers and other end-users. The Partnership’s propane supply primarily originates from both its refinery/gas supply contracts and its other owned or managed logistics and marketing assets. The Partnership generally sells propane at a fixed or posted price at the time of delivery and, in some circumstances, the Partnership earns margin on a net-back basis.

The wholesale propane marketing business is significantly impacted by weather-driven demand, particularly in the winter, which can impact the price of propane in the markets it serves and impact the ability to deliver propane to satisfy peak demand.
 
Refinery Services. In its refinery services business, the Partnership typically provides NGL balancing services via contractual arrangements with refiners to purchase and/or market propane and to supply butanes. The Partnership uses its commercial transportation assets (discussed below) and contracts for and uses the storage, transportation and distribution assets included in its Logistics Assets segment to assist refinery customers in managing their NGL product demand and production schedules. This includes both feedstocks consumed in refinery processes and the excess NGLs produced by those same refining processes. Under typical net-back purchase contracts, the Partnership generally retains a portion of the resale price of NGL sales or receives a fixed minimum fee per gallon on products sold. Under net-back sales contracts, fees are earned for locating and supplying NGL feedstocks to the refineries based on a percentage of the cost to obtain such supply or a minimum fee per gallon.

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

Commercial Transportation. The Partnership’s NGL transportation and distribution infrastructure includes a wide range of assets supporting both third party customers and the delivery requirements of its marketing and asset management business. The Partnership provides fee-based transportation services to refineries and petrochemical companies throughout the Gulf Coast area. The Partnership’s assets are also deployed to serve its wholesale distribution terminals, fractionation facilities, underground storage facilities and pipeline injection terminals. These distribution assets provide a variety of ways to transport products to and from its customers. The Partnership’s transportation assets, as of December 31, 2010, include:

•  
approximately 760 railcars that the Partnership leases and manages;

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

•  
21 company-owned pressurized NGL barges.
 
Natural Gas Marketing. The Partnership also markets natural gas available to the Partnership from the Gathering and Processing segments, and purchases and resells natural gas in selected United States markets.
 
The following table details the Marketing and Distribution segment’s Terminal Facilities:

 
 
 
 
 
 
 
 
Throughput for
 
 
 
 
 
 
 
 
 
 
Year Ended
 
Usable Storage
 
 
 
 
County/Parish,
 
 
 
December 31, 2010
 
Capacity
Facility
 
% Owned
 
State
 
Description
 
( Million gallons) (1)
 
( Million gallons)
Calvert City Terminal
 
100
 
Marshall, KY
 
Propane terminal
 
47.2 
 
 0.1 
Greenville Terminal
 
100
 
Washington, MS
 
Marine propane terminal
 
23.1 
 
 1.7 
Port Everglades Terminal
 
100
 
Broward, FL
 
Marine propane terminal
 
23.8 
 
 1.7 
Tyler Terminal
 
100
 
Smith, TX
 
Propane terminal
 
9.3 
 
 0.2 
Abilene Transport (2)
 
100
 
Taylor, TX
 
Raw NGL transport terminal
 
12.4 
 
Less than 0.1
Bridgeport Transport (2)
 
100
 
Jack, TX
 
Raw NGL transport terminal
 
49.6 
 
 0.1 
Gladewater Transport (2)
 
100
 
Gregg, TX
 
Raw NGL transport terminal
 
20.5 
 
 0.4 
Hammond Transport
 
100
 
Tangipahoa, LA
 
Transport terminal
 
31.6 
 
No storage
Chattanooga Terminal
 
100
 
Hamilton, TN
 
Propane terminal
 
18.3 
 
 1.0 
Sparta Terminal
 
100
 
Sparta, NJ
 
Propane terminal
 
10.7 
 
 0.2 
Hattiesburg Terminal (3)
 
50
 
Forrest, MS
 
Propane terminal
 
264.8 
 
 269.6 
Winona Terminal
 
100
 
Flagstaff, AZ
 
Propane terminal
 
4.4 
 
 0.3 
 
_______
(1)  
Throughputs include volumes related to exchange agreements and third party storage agreements.
(2)  
Volumes reflect total transport and injection volumes.
(3)  
Throughput volume is based on 100% ownership.

Operational Risks and Insurance

The Partnership is subject to all risks inherent in the midstream natural gas business. These risks include, but are not limited to, explosions, fires, mechanical failure, terrorist attacks, product spillage, weather, nature and inadequate maintenance of rights-of-way and could result in damage to or destruction of operating assets and other property, or could result in personal injury, loss of life or polluting the environment, as well as curtailment or suspension of operations at the affected facility. We maintain, on behalf of ourselves and our subsidiaries, including the Partnership, general public liability, property, boiler and machinery and business interruption insurance in amounts that we consider to be appropriate for such risks. Such insurance is subject to deductibles that we consider reasonable and not excessive given the current insurance market environment. The costs associated with these insurance coverages increased significantly following Hurricanes Katrina and Rita in 2005. Insurance premiums, deductibles and co-insurance requirements increased substantially, and terms were generally less favorable than terms that were obtained prior to those hurricanes. Insurance market conditions worsened again as a result of industry losses including those sustained from Hurricanes Gustav and Ike in September 2008, and as a result of volatile conditions in the financial markets. As a result, in 2009, the Partnership experienced further increases in deductibles and premiums, and further reductions in coverage and limits. During 2010, it saw the insurance market conditions improve slightly.

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

 
Significant Customers

The following table lists the percentage of the Partnership’s consolidated sales and consolidated product purchases with the Partnership’s significant customers and suppliers:

 
 
2010 
 
2009 
 
2008 
% of consolidated revenues
 
 
 
 
 
 
Chevron Phillips Chemical Company LLC
10%
 
15%
 
19%
 
 
 
 
 
 
 
% of consolidated product purchases
 
 
 
 
 
 
Louis Dreyfus Energy Services L.P.
10%
 
11%
 
9%

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

The Partnership has agreements with Chevron Phillips Chemical Company LLC (“CPC”), a separate joint venture affiliate of Chevron, pursuant to which the Partnership supplies a significant portion of CPC’s NGL feedstock needs for petrochemical plants in the Texas Gulf Coast area and a related services agreement, pursuant to which the Partnership provides storage and logistical services to CPC for feed stocks and products produced from the petrochemical plants. The services contract was renegotiated in 2008 with key components having a 10 year term. In September 2009, CPC executed contracts to replace the previously terminated agreement with a new feedstock and storage agreement effective for a term of 5 years, which will renew annually following the end of the five year term unless terminated by either party. We believe that the Partnership is well positioned to retain CPC as a customer based on the Partnership’s long-standing history of customer service, the criticality of the service provided, the integrated nature of facilities and the difficulty and high cost associated with replicating the Partnership’s assets. In addition to these two agreements, The Partnership has fractionation agreements in place with CPC for Y-grade streams and butanes.

Competition

The Partnership faces 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 the Partnership’s gathering and processing operations include other natural gas gatherers and processors, such as major interstate and intrastate pipeline companies, master limited partnerships and oil and gas producers. The Partnership’s major competitors for natural gas supplies in its current operating regions include Atlas Gas Pipeline Company, Copano Energy, L.L.C. (“Copano”), WTG Gas Processing, L.P. (“WTG”), DCP Midstream Partners LP (“DCP”), Devon Energy Corp (“Devon”), Enbridge Inc., GulfSouth Pipeline Company, LP, Hanlon Gas Processing, Ltd., J W Operating Company, Louisiana Intrastate Gas and several other interstate pipeline companies. Many of its competitors have greater financial resources than the Partnership possesses.

The Partnership also competes for NGL products to market through its NGL Logistics and Marketing division. The Partnership’s competitors include major oil and gas producers who market NGL products for their own account and for others. Additionally, the Partnership competes with several other NGL marketing companies, including Enterprise Products Partners L.P., DCP, ONEOK and BP p.l.c.

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

Regulation of Operations

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

Regulation of Interstate Natural Gas Pipelines

The VGS is regulated by FERC under the Natural Gas Act of 1938 (“NGA”), and the Natural Gas Policy Act of 1978 (“NGPA”). VGS operates under a FERC approved, open-access tariff that establishes rates and terms and conditions under which the system provides services to its customers. Pursuant to FERC’s jurisdiction, existing pipeline rates and/or terms and conditions of service may be challenged by customer complaint or by FERC and proposed rate changes or changes in the terms and conditions of service may be challenged by protest. Generally, FERC’s authority extends to: transportation of natural gas; rates and charges for natural gas transportation; certification and construction of new facilities; extension or abandonment of services and facilities; maintenance of accounts and records; commercial relationships and communications between pipelines and certain affiliates; terms and conditions of service and service contracts with customers; depreciation and amortization policies; and acquisition and disposition of facilities.

VGS holds a certificate of public convenience and necessity issued by FERC permitting the construction, ownership, and operation of its interstate natural gas pipeline facilities and the provision of transportation services. This certificate authorization requires VGS to provide on a nondiscriminatory basis open-access services to all customers who qualify under its FERC gas tariff. FERC has the power to prescribe the accounting treatment of items for regulatory purposes. Thus, the books and records of VGS may be periodically audited by FERC.

 
The maximum recourse rates that may be charged by VGS for its services are established through FERC’s ratemaking process. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of service including recovery of and a return on the pipeline’s investment. Key determinants in the ratemaking process are costs of providing service, allowed rate of return and volume throughput and contractual capacity commitment assumptions. VGS is permitted to discount its firm and interruptible rates without further FERC authorization down to the variable cost of performing service, provided they do not “unduly discriminate.” The applicable recourse rates and terms and conditions for service are set forth in each pipeline’s FERC approved tariff. Rate design and the allocation of costs also can impact a pipeline’s profitability.
 
Gathering Pipeline Regulation

The Partnership’s natural gas gathering operations are typically subject to ratable take and common purchaser statutes in the states in which it operates. The common purchaser statutes generally require 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 or one source of supply over another. The regulations under these statutes can have the effect of imposing some restrictions on the Partnership’s ability as an owner of gathering facilities to decide with whom it contracts to gather natural gas. The states in which the Partnership operates 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 the Partnership charges for gathering are deemed just and reasonable unless challenged in a complaint. We cannot predict whether such a complaint will be filed against the Partnership 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 NGA exempts natural gas gathering facilities from regulation as a natural gas company by FERC under the NGA. We believe that the natural gas pipelines in the Partnership’s 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 the Partnership’s 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. The Partnership’s natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on the Partnership’s 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 the Partnership’s future operations in Texas.

Intrastate Pipeline Regulation

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

The Partnership’s intrastate pipelines located in Texas are regulated by the RRC. The Partnership’s Texas intrastate pipeline, Targa Intrastate Pipeline LLC (“Targa Intrastate”), owns the intrastate pipeline that transports natural gas from the Partnership’s Shackelford processing plant to an interconnect with Atmos Pipeline-Texas that in turn delivers gas to the West Texas Utilities Company’s Paint Creek Power Station. Targa Intrastate also owns a 1.65 mile, 10 inch diameter intrastate pipeline that transports natural gas from a third-party gathering system into the Chico System in Denton County, Texas. Targa Intrastate is a gas utility subject to regulation by the RRC and has a tariff on file with such agency. The Partnership notes that the RRC is subject to a sunset condition.  If the Texas Legislature does not take action to continue the RRC, the RRC will be abolished effective September 1, 2011, and will begin a one-year wind-down process.  The Sunset Advisory Commission has recommended certain organizational changes be made to the RRC.  The Partnership cannot tell what, if any, changes will be made to the RRC as a result of the pending regular session or any called sessions of the Texas Legislature in 2011, but the Partnership does not believe that any such changes would affect its business in a way that would be materially different from the way such changes would affect its competitors.

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

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 the Partnership charges for intrastate transportation are deemed just and reasonable unless challenged in a complaint. We cannot predict whether such a complaint will be filed against the Partnership in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties.
 
 
Regulation of NGL intrastate pipelines

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

Natural Gas Processing

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

The Partnership’s processing facilities and 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 the Partnership’s processing operations and its natural gas and NGL marketing operations. We do not believe that the Partnership would be affected by any such FERC action materially differently than other natural gas processors and natural gas and NGL marketers with whom it competes.
 
The ability of the Partnership’s processing facilities and pipelines to deliver natural gas into third-party natural gas pipeline facilities is directly impacted by the gas quality specifications required by those pipelines. In 2006, FERC issued a policy statement on provisions governing gas quality and interchangeability in the tariffs of interstate gas pipeline companies and a separate order declining to set generic prescriptive national standards. FERC strongly encouraged all natural gas pipelines subject to its jurisdiction to adopt, as needed, gas quality and interchangeability standards in their FERC gas tariffs modeled on the interim guidelines issued by a group of industry representatives, headed by the Natural Gas Council (“NGC+ Work Group”), or to explain how and why their tariff provisions differ. We do not believe that the adoption of the NGC+ Work Group’s gas quality interim guidelines by a pipeline that either directly or indirectly interconnects with the Partnership’s facilities would materially affect the Partnership’s 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 the Partnership buys and sells 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 the Partnership’s physical purchases and sales of these energy commodities and any related hedging activities that it undertakes, the Partnership is required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodities Futures Trading Commission (“CFTC”). See “—Other Federal Laws and Regulation Affecting Our Industry—Energy Policy Act of 2005.” Starting May 1, 2009, the Partnership was required to report to FERC information regarding natural gas sale and purchase transactions for some of its operations depending on the volume of natural gas transacted during the prior calendar year. See “—Other Federal Laws and Regulation Affecting Our Industry—FERC Market Transparency Rules.” Should the Partnership violate the anti-market manipulation laws and regulations, it 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 Operations

The Partnership’s 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 the Partnership’s business, see “Risk Factors—Risks Related to Our Business.”

Interstate Common Carrier Liquids Pipeline Regulation

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

 
Other Federal Laws and Regulation Affecting Our Industry

Energy Policy Act of 2005(“EPA Act of 2005”)

The EPA Act of 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, EPA Act of 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 EPA Act of 2005 provides FERC with the power to assess civil penalties of up to $1 million per day for violations of the NGA and $1 million per violation per day for violations of the NGPA. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce, including VGS. In 2006, FERC issued Order 670 to implement the anti-market manipulation provision of EPA Act of 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 a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing  (Order 704), the daily schedule flow and capacity posting requirements under Order 720, and the quarterly reporting requirement under Order 735. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

FERC Standards of Conduct for Transmission Providers

On October 16, 2008, FERC issued new standards of conduct for transmission providers (Order 717) to regulate the manner in which interstate natural gas pipelines may interact with their marketing affiliates based on an employee separation approach. A “Transmission Provider” includes an interstate natural gas pipeline that provides open access transportation pursuant to FERC’s regulations. Under these rules, a Transmission Provider’s transmission function employees (including the transmission function employees of any of its affiliates) must function independently from the Transmission Provider’s marketing function employees (including the marketing function employees of any of its affiliates). FERC clarified on October 15, 2009 in a rehearing order, Order 717-A, however, that if a Hinshaw pipeline affiliated with a Transmission Provider engages in off-system sales of gas that has been transported on the Transmission Provider’s affiliated pipeline, then the Transmission Provider and the Hinshaw pipeline (which is engaging in marketing functions) will be required to observe the Standards of Conduct by, among other things, having the marketing function employees function independently from the transmission function employees. The Partnership’s only Hinshaw pipeline, TLI, does not engage in any off-system sales of gas that have been transported on an affiliated Transmission Provider, and we do not believe that the Partnership’s operations will be affected by the new standards of conduct. FERC further clarified Order 717-A in a rehearing order, Order 717-B, on November 16, 2009 and in Order 717-C, on April 16, 2010. However, Orders 717-B and 717-C did not substantively alter the rules promulgated under Orders 717 and 717-A. Requests for rehearing of Order 717-C have been filed and are currently pending before FERC. Our only Transmission Provider, VGS, does not engage in any transactions with marketing affiliates, and we do not believe that our operations will be affected by the new standards of conduct. We have no way to predict with certainty whether and to what extent FERC will revise the new standards of conduct in response to those requests for rehearing.
 
FERC Market Transparency Rules

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

On November 20, 2008, FERC issued a final rule on daily scheduled flows and capacity posting requirements (Order 720). Under Order 720, as clarified in orders on clarification and rehearing certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtu of gas over the previous three calendar years, are required to post daily certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000 MMBtu/d and interstate pipelines are required to post information regarding the provision of no-notice service. The Partnership takes the position that, at this time, all of its entities are exempt from this rule as currently written.

On May 20, 2010, the FERC issued Order No. 735, which requires intrastate pipelines providing transportation services under Section 311 of the NGPA and “Hinshaw” pipelines operating under Section 1(c) of the NGA to report on a quarterly basis more detailed transportation and storage transaction information, including: rates charged by the pipeline under each contract; receipt and delivery points and zones or segments covered by each contract; the quantity of natural gas the shipper is entitled to transport, store, or deliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and the shipper. Order No. 735 further requires that such information must be supplied through a new electronic reporting system and will be posted on FERC’s website, and that such quarterly reports may not contain information redacted as privileged. The FERC promulgated this Rule after determining that such transactional information would help shippers make more informed purchasing decisions and would improve the ability of both shippers and the FERC to monitor actual transactions for evidence of market power or undue discrimination. Order No. 735 also extends the Commission’s periodic review of the rates charged by the subject pipelines from three years to five years. Order No. 735 becomes effective on April 1, 2011.  On December 16, 2010, the Commission issued Order No. 735-A.  In Order No. 735-A, the Commission generally reaffirmed Order No. 735 requiring section 311 and Hinshaw pipelines to report on a quarterly basis storage and transportation transactions containing specific information for each transaction, aggregated by contract.  Order No. 735-A did grant rehearing of three requests, including removing the requirement that the quarterly reports include the contract end-date for interruptible transactions, eliminating the increased per-customer revenue reporting requirements, and extending the deadline for submitting the quarterly reports from 30 days to 60 days following the quarter end date. As currently written, this rule does not apply to the Partnership’s Hinshaw pipelines. We will continue to monitor developments with respect to this rulemaking.
 
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 the Partnership’s natural gas operations. We do not believe that the Partnership would be affected by any such FERC action materially differently than other midstream natural gas companies with whom it competes.

Environmental, Health and Safety Matters

General

The Partnership’s operations are subject to stringent and complex federal, state and local laws and regulations pertaining to health, safety and the environment. As with the industry generally, compliance with current and anticipated environmental laws and regulations increases the Partnership’s overall cost of business, including its 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 the Partnership can handle or dispose of its wastes; limit or prohibit construction activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; impose specific health and safety criteria addressing worker protection, require investigatory and remedial action to mitigate pollution conditions caused by the Partnership’s 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 the Partnership’s activities.

The Partnership has implemented programs and policies designed to keep its 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 reinterpretation 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 the Partnership’s operations and financial position. The Partnership may be unable to pass on such increased compliance costs to its customers. Moreover, accidental releases or spills may occur in the course of the Partnership’s operations and we cannot assure you that the Partnership 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 the Partnership is in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on the Partnership, 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 the Partnership’s business operations are subject and for which compliance may have a material adverse impact on its capital expenditures, results of operations or financial position.

Hazardous Substances and Waste

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) 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 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. The Partnership generates materials in the course of its 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.

The Partnership also generates solid wastes, including hazardous wastes that are subject to the requirements of Resource Conservation and Recovery Act (“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 its operations, the Partnership generates 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 the RCRA hazardous waste regulations. However, it is possible that future changes in law or regulation could result in these wastes, including wastes currently generated during the Partnership’s 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 the Partnership’s capital expenditures and operating expenses as well as those of the oil and gas industry in general.

The Partnership currently owns or leases and has in the past owned or leased, properties that for many years have been used for midstream natural gas and NGL activities. Although the Partnership has utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or 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 wastes was not under the Partnership’s control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, the Partnership 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 the Partnership’s 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 the Partnership 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. The Partnership is currently reviewing the air emissions monitoring systems at certain of its facilities. The Partnership 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 its 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 the Partnership’s operations.

Climate Change

There is increasing attention in the United States and worldwide concerning the issue of climate change and the effect of Green House Gasses (“GHGs”). In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to proceed with the adoption and implementation of regulations restricting emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA already has adopted two sets of regulations regarding possible future regulation of GHG emissions under the Clean Air Act, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which would regulate emissions of GHGs from large stationary sources of emissions, such as power plants or industrial facilities, effective January 2, 2011. In June 2010, EPA published its final rule to address permitting of GHG emissions from stationary sources under the Clean Air Act’s Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The final rule tailors the PSD and Title V permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting.  The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing or requiring state environmental agencies to implement the rules. Moreover, on October 30, 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., on an annual basis beginning in 2011 for emissions occurring in 2010. On November 8, 2010, the EPA adopted amendments to this GHG reporting rule, expanding the monitoring and reporting obligations to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities on an annual basis, beginning in 2012 for emissions occurring in 2011.

In addition, the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, and almost half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and NGL fractionation plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. The adoption and implementation of any regulations imposing GHG reporting or permitting obligations on, or limiting emissions of GHGs from, the Partnership’s equipment and operations could require the Partnership to incur costs to reduce emissions of GHGs associated with its operations, could adversely affect its performance of operations in the absence of any permits that may be required to regulate emission of greenhouse gases, or could adversely affect demand for its natural gas and NGL processing services.

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have in adverse effect on the Partnership’s assets and operations.

Water Discharges

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

It is customary to recover natural gas from deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production.  The process is typically regulated by state oil and gas commissions.  However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s (“SDWA”) Underground Injection Control Program.  While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision.  At the same time, the EPA has commenced a study of the potential adverse impact of hydraulic fracturing activities, with results of the study expected to be available in late 2012, and a committee of the U.S. House of Representatives is conducting an investigation of hydraulic fracturing practices.  Also, legislation was introduced in the recently completed session of Congress to amend the SDWA to subject hydraulic fracturing operations to regulation under the Act and to require the disclosure of chemicals used by the oil and natural gas industry, and such legislation could be introduced in the current session of Congress.  Moreover, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. Adoption of legislation or of any implementing regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of natural gas and, in turn, adversely affect our revenues and results of operation by decreasing the volumes of natural gas that the Partnership gathers, processes and fractionates.

 
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 the Partnership’s plants, and the Partnership’s 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 the Partnership is in substantial compliance with the CWA, SDWA, 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 the Partnership’s facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that the Partnership is in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause the Partnership to incur additional costs or become subject to operating restrictions or bans in the affected areas.
 
Pipeline Safety

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

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

In addition, states have adopted regulations, similar to existing DOT regulations, for intrastate gathering and transmission lines. Texas and Louisiana have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastate pipelines transporting natural gas and NGLs. We currently estimate an annual average cost of $2.2 million for years 2011 through 2013 to perform necessary integrity management program testing on the Partnership’s 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 the Partnership’s financial condition or results of operations.

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

 
Employee Health and Safety

We and the Partnership 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 the Partnership’s operations and that this information be provided to employees, state and local government authorities and citizens. The Partnership and the entities in which it owns 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. The Partnership has an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that the Partnership is in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Title to Properties and Rights-of-Way

The Partnership’s real property falls into two categories: (1) parcels that it owns in fee and (2) parcels in which its interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for its operations. Portions of the land on which the Partnership’s plants and other major facilities are located are owned by the Partnership in fee title, and we believe that the Partnership has satisfactory title to these lands. The remainder of the land on which the Partnership’s plant sites and major facilities are located is held by the Partnership pursuant to ground leases between the Partnership, as lessee, and the fee owner of the lands, as lessors. The Partnership, or its predecessors, has leased these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that the Partnership has satisfactory leasehold estates to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by the Partnership and we believe that the Partnership has satisfactory title to all of its material leases, easements, rights-of-way, permits and licenses.

We 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, we 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, causing us 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 our holding of title to any part of such assets subject to future conveyance or as our nominee.

Employees

Through our subsidiaries, we employ 1,020 people who primarily support the Partnership’s operations. None of these employees are covered by collective bargaining agreements. We consider our employee relations to be good.

Financial Information by Segment

See “Segment Information” included under Note 21 to our “Consolidated Financial Statements” beginning on page F-1 of this Annual Report for a presentation of financial results by segment and see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations of the Partnership – By Segment” for a discussion of our financial results by segment.
 
Available Information

We make certain filings with the Securities and Exchange Commission (“SEC”), including our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports. We make such filings available free of charge through our website, http://www.targaresources.com, as soon as reasonably practicable after they are filed with the SEC. The filings are also available through the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. Also, these filings are available on the internet at http://www.sec.gov. Our press releases and recent analyst presentations are also available on our website.
 
 
Item 1A. Risk Factors
 
The nature of our business activities subjects 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. If any of the following risks were actually to occur, then our business, financial condition, cash flows and results of operations could be materially adversely affected.

Risks Related to Our Business

Our cash flow is dependent upon the ability of the Partnership to make cash distributions to us.

Our cash flow consists of cash distributions from the Partnership. The amount of cash that the Partnership will be able to distribute to its partners, including us, each quarter principally depends upon the amount of cash it generates from its business. For a description of certain factors that can cause fluctuations in the amount of cash that the Partnership generates from its business, please read “—Risks Inherent in the Partnership’s Business” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors That Significantly Affect Our Results.” The Partnership may not have sufficient available cash each quarter to continue paying distributions at their current level or at all. If the Partnership reduces its per unit distribution, because of reduced operating cash flow, higher expenses, capital requirements or otherwise, we will have less cash available for distribution and would probably be required to reduce the dividend per share of common stock. The amount of cash the Partnership has available for distribution depends primarily upon the Partnership’s cash flow, including cash flow from the release of reserves as well as borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, the Partnership may make cash distributions during periods when it records losses and may not make cash distributions during periods when it records profits.

Once we receive cash from the Partnership and the General Partner, our ability to distribute the cash received to our stockholders is limited by a number of factors, including:
 
 
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our obligation to (i) satisfy tax obligations associated with previous sales of assets to the Partnership, (ii) reimburse the Partnership for certain capital expenditures related to Versado and (iii) provide the Partnership with limited quarterly distribution support through 2011, all as described in more detail in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources;”

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interest expense and principal payments on any indebtedness we incur;

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 restrictions on distributions contained in any existing or future debt agreements;

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our general and administrative expenses, including expenses we incur as a result of being a public company as well as other operating expenses;
 
 
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expenses of the General Partner;

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 income taxes;

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 reserves we establish in order for us to maintain our 2% general partner interest in the Partnership upon the issuance of additional partnership securities by the Partnership; and

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 reserves our board of directors establishes for the proper conduct of our business, to comply with applicable law or any agreement binding on us or our subsidiaries or to provide for future dividends by us.

The actual amount of cash that is available for dividends to our stockholders will depend on numerous factors, many of which are beyond our control.

A reduction in the Partnership’s distributions will disproportionately affect the amount of cash distributions to which we are entitled.

Our ownership of the IDRs in the Partnership entitles us to receive specified percentages of the amount of cash distributions made by the Partnership to its limited partners only in the event that the Partnership distributes more than $0.3881 per unit for such quarter. As a result, the holders of the Partnership’s common units have a priority over our IDRs to the extent of cash distributions by the Partnership up to and including $0.3881 per unit for any quarter.

Our IDRs entitle us to receive increasing percentages, up to 48%, of all cash distributed by the Partnership. Because the Partnership’s distribution rate is currently above the maximum target cash distribution level on the IDRs, future growth in distributions we receive from the Partnership will not result from an increase in the target cash distribution level associated with the IDRs. Furthermore, a decrease in the amount of distributions by the Partnership to less than $0.50625 per unit per quarter would reduce the General Partner’s percentage of the incremental cash distributions above $0.3881 per common unit per quarter from 48% to 23%. As a result, any such reduction in quarterly cash distributions from the Partnership would have the effect of disproportionately reducing the distributions that we receive from the Partnership based on our IDRs as compared to distributions we receive from the Partnership with respect to our 2% general partner interest and our common units.

If the Partnership’s unitholders remove the General Partner, we would lose our general partner interest and IDRs in the Partnership and the ability to manage the Partnership.

We currently manage our investment in the Partnership through our ownership interest in the General Partner. The Partnership’s partnership agreement, however, gives unitholders of the Partnership the right to remove the General Partner upon the affirmative vote of holders of 66⅔% of the Partnership’s outstanding units. If the General Partner were removed as general partner of the Partnership, it would receive cash or common units in exchange for its 2% general partner interest and the IDRs and would also lose its ability to manage the Partnership. While the cash or common units the General Partner would receive are intended under the terms of the Partnership’s partnership agreement to fully compensate us in the event such an exchange is required, the value of the investments we make with the cash or the common units may not over time be equivalent to the value of the general partner interest and the IDRs had the General Partner retained them.

 
In addition, if the General Partner is removed as general partner of the Partnership, we would face an increased risk of being deemed an investment company. Please read “—If in the future we cease to manage and control the Partnership, we may be deemed to be an investment company under the Investment Company Act of 1940.”

The Partnership, without our stockholders’ consent, may issue additional common units or other equity securities, which may increase the risk that the Partnership will not have sufficient available cash to maintain or increase its cash distribution level per common unit.

Because the Partnership distributes to its partners most of the cash generated by its operations, it relies primarily upon external financing sources, including debt and equity issuances, to fund its acquisitions and expansion capital expenditures. Accordingly, the Partnership has wide latitude to issue additional common units on the terms and conditions established by its general partner. We receive cash distributions from the Partnership on the general partner interest, IDRs and common units that we own. Because a significant portion of the cash we receive from the Partnership is attributable to our ownership of the IDRs, payment of distributions on additional Partnership common units may increase the risk that the Partnership will be unable to maintain or increase its quarterly cash distribution per unit, which in turn may reduce the amount of distributions we receive attributable to our common units, general partner interest and IDRs and the available cash that we have to pay as dividends to our stockholders.
 
The General Partner, with our consent but without the consent of our stockholders, may limit or modify the incentive distributions we are entitled to receive, which may reduce cash dividends to you.

We own the General Partner, which owns the IDRs in the Partnership that entitle us to receive increasing percentages, up to a maximum of 48% of any cash distributed by the Partnership as certain target distribution levels are reached in excess of $0.3881 per common unit in any quarter. A substantial portion of the cash flow we receive from the Partnership is provided by these IDRs. Because of the high percentage of the Partnership’s incremental cash flow that is distributed to the IDRs, certain potential acquisitions might not increase cash available for distribution per Partnership unit. In order to facilitate acquisitions by the Partnership or for other reasons, the board of directors of the General Partner may elect to reduce the IDRs payable to us with our consent. These reductions may be permanent reductions in the IDRs or may be reductions with respect to cash flows from the potential acquisition. If distributions on the IDRs were reduced for the benefit of the Partnership units, the total amount of cash distributions we would receive from the Partnership, and therefore the amount of cash dividends we could pay to our stockholders, would be reduced.

In the future, we may not have sufficient cash to pay estimated dividends.

Because our only source of operating cash flow consists of cash distributions from the Partnership, the amount of dividends we are able to pay to our stockholders may fluctuate based on the level of distributions the Partnership makes to its partners, including us. The Partnership may not continue to make quarterly distributions at the 2010 fourth quarter distribution level of $0.5475 per common unit, or may not distribute any other amount, or increase its quarterly distributions in the future. In addition, while we would expect to increase or decrease dividends to our stockholders if the Partnership increases or decreases distributions to us, the timing and amount of such changes in distributions, if any, will not necessarily be comparable to the timing and amount of any changes in dividends made by us. Factors such as reserves established by our board of directors for our estimated general and administrative expenses of being a public company as well as other operating expenses, reserves to satisfy our debt service requirements, if any, and reserves for future dividends by us may affect the dividends we make to our stockholders. The actual amount of cash that is available for dividends to our stockholders will depend on numerous factors, many of which are beyond our control.

Our cash dividend policy limits our ability to grow.

Because we plan on distributing a substantial amount of our cash flow, our growth may not be as fast as the growth of businesses that reinvest their available cash to expand ongoing operations. In fact, because our only cash-generating assets are direct and indirect partnership interests in the Partnership, our growth will be substantially dependent upon the Partnership. If we issue additional shares of common stock or we were to incur debt, the payment of dividends on those additional shares or interest on that debt could increase the risk that we will be unable to maintain or increase our cash dividend levels.

Our rate of growth may be reduced to the extent we purchase additional units from the Partnership, which will reduce the relative percentage of the cash we receive from the IDRs.

Our business strategy includes, where appropriate, supporting the growth of the Partnership by purchasing the Partnership’s units or lending funds or providing other forms of financial support to the Partnership to provide funding for the acquisition of a business or asset or for a growth project. To the extent we purchase common units or securities not entitled to a current distribution from the Partnership, the rate of our distribution growth may be reduced, at least in the short term, as less of our cash distributions will come from our ownership of IDRs, whose distributions increase at a faster rate than those of our other securities.

We have a credit facility that contains various restrictions on our ability to pay dividends to our stockholders, borrow additional funds or capitalize on business opportunities.

We have a credit facility that contains various operating and financial restrictions and covenants. Our ability to comply with these restrictions and covenants may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If we are unable to comply with these restrictions and covenants, any future indebtedness under this credit facility may become immediately due and payable and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments.
 
 
Our credit facility limits our ability to pay dividends to our stockholders during an event of default or if an event of default would result from such dividend.  In addition, any future borrowings may:

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adversely affect our ability to obtain additional financing for future operations or capital needs;

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limit our ability to pursue acquisitions and other business opportunities;

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make our results of operations more susceptible to adverse economic or operating conditions; or

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limit our ability to pay dividends.
 
Our payment of any principal and interest will reduce our cash available for dividends to holders of common stock. In addition, we are able to incur substantial additional indebtedness in the future. If we incur additional debt, the risks associated with our leverage would increase. For more information regarding our credit facility, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

If dividends on our shares of common stock are not paid with respect to any fiscal quarter, including those at the anticipated initial dividend rate, our stockholders will not be entitled to receive that quarter’s payments in the future.

Dividends to our stockholders will not be cumulative. Consequently, if dividends on our shares of common stock are not paid with respect to any fiscal quarter, including those at the anticipated initial dividend rate, our stockholders will not be entitled to receive that quarter’s payments in the future.

The Partnership’s practice of distributing all of its available cash may limit its ability to grow, which could impact distributions to us and the available cash that we have to dividend to our stockholders.

Because our only cash-generating assets are common units and general partner interests in the Partnership, including the IDRs, our growth will be dependent upon the Partnership’s ability to increase its quarterly cash distributions. The Partnership has historically distributed to its partners most of the cash generated by its operations. As a result, it relies primarily upon external financing sources, including debt and equity issuances, to fund its acquisitions and expansion capital expenditures. Accordingly, to the extent the Partnership is unable to finance growth externally; its ability to grow will be impaired because it distributes substantially all of its available cash. Also, if the Partnership incurs additional indebtedness to finance its growth, the increased interest expense associated with such indebtedness may reduce the amount of available cash that we can distribute to you. In addition, to the extent the Partnership issues additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that the Partnership will be unable to maintain or increase its per unit distribution level, which in turn may impact the cash available for dividends to our stockholders.

Restrictions in the Partnership’s senior secured credit facility and indentures could limit its ability to make distributions to us.

The Partnership’s senior secured credit facility and indentures contain covenants limiting its ability to incur indebtedness, grant liens and make distributions. The Partnership’s senior secured credit facility also contains covenants requiring the Partnership to maintain certain financial ratios. The Partnership is prohibited from making any distribution to unitholders if such distribution would cause an event of default or otherwise violate a covenant under its senior secured credit facility or the indentures.

If in the future we cease to manage and control the Partnership, we may be deemed to be an investment company under the Investment Company Act of 1940.

If we cease to manage and control the Partnership and are deemed to be an investment company under the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act of 1940, obtain an exemption from the SEC or modify our organizational structure or our contractual rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with the Partnership, including the purchase and sale of certain securities or other property to or from the Partnership, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us and the Partnership, and adversely affect the price of our common stock.

 
Our historical financial information may not be representative of our future performance.

The historical financial information included in this annual report is derived from our historical financial statements for periods including prior to our initial public offering in December 2010. Our audited historical financial statements were prepared in accordance with GAAP. Accordingly, the historical financial information included in this annual report does not reflect what our results of operations and financial condition would have been had we been a public entity during the periods presented, or what our results of operations and financial condition will be in the future.

If we lose any of our named executive officers, our business may be adversely affected.

Our success is dependent upon the efforts of the named executive officers. Our named executive officers are responsible for executing the Partnership’s business strategy and, when appropriate to our primary business objective, facilitating the Partnership’s growth through various forms of financial support provided by us, including, but not limited to, modifying the Partnership’s IDRs, exercising the Partnership’s IDR reset provision contained in its partnership agreement, making loans, making capital contributions in exchange for yielding or non-yielding equity interests or providing other financial support to the Partnership. There is substantial competition for qualified personnel in the midstream natural gas industry.  We may not be able to retain our existing named executive officers or fill new positions or vacancies created by expansion or turnover. We have not entered into employment agreements with any of our named executive officers. In addition, we do not maintain “key man” life insurance on the lives of any of our named executive officers. A loss of one or more of our named executive officers could harm our and the Partnership’s business and prevent us from implementing our and the Partnership’s business strategy.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. In addition, potential changes in accounting standards might cause us to revise our financial results and disclosure in the future.

Effective internal controls are necessary for us to provide timely and reliable financial reports and effectively prevent fraud. If we cannot provide timely and reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We continue to enhance our internal controls and financial reporting capabilities. These enhancements require a significant commitment of resources, personnel and the development and maintenance of formalized internal reporting procedures to ensure the reliability of our financial reporting. Our efforts to update and maintain our internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting in the future, including future compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective controls, or difficulties encountered in the effective improvement of our internal controls could prevent us from timely and reliably reporting our financial results and may harm our operating results. Ineffective internal controls could also cause investors to lose confidence in our reported financial information. In addition, the Financial Accounting Standards Board or the SEC could enact new accounting standards that might impact how we or the Partnership are required to record revenues, expenses, assets and liabilities. Any significant change in accounting standards or disclosure requirements could have a material effect on our business, results of operations, financial condition and ability to service our and our subsidiaries’ debt obligations.

An increase in interest rates may cause the market price of our common stock to decline.

Like all equity investments, an investment in our common stock is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments. Reduced demand for our common stock resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common stock to decline.
 
The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company with listed equity securities, we must comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the New York Stock Exchange, or NYSE, with which we were not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. These new laws and regulations require us to:

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institute a more comprehensive compliance function;

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design, establish, evaluate and maintain an additional system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;

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comply with rules promulgated by the NYSE;

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prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

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establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;

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involve and retain to a greater degree outside counsel and accountants in the above activities; and

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augment our investor relations function.
 
 
In addition, we also expect that being a public company could require us to accept less director and officer liability insurance coverage than we desire or to incur additional costs to maintain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our Audit Committee, and qualified executive officers.

Future sales of our common stock in the public market could lower our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We or our stockholders may sell shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or convertible securities. As of December 31, 2010 we have 42,292,348 outstanding shares of common stock. This number consists of 18,831,250 shares that the selling stockholders sold in our initial public offering. Following our initial public offering, the existing shareholders owned approximately 23.5 million shares, or 55.5% of our total outstanding shares. All such shares may be sold into the market in the future. Certain of our existing stockholders are party to a registration rights agreement with us which requires us to affect the registration of their shares in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement of our initial public offering.

We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock.  Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

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a classified board of directors, so that only approximately one-third of our directors are elected each year;

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limitations on the removal of directors; and

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limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.

Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our board of directors. We anticipate opting out of this provision of Delaware law until such time as Warburg Pincus and certain transferees; do not beneficially own at least 15% of our common stock. Please read “Description of Our Capital Stock—Anti-Takeover Effects of Provisions of Our Amended and Restated Certificate of Incorporation, Our Amended and Restated Bylaws and Delaware Law.”

We have a significant stockholder, which will limit other stockholders’ ability to influence corporate matters and may give rise to conflicts of interest.

Affiliates of Warburg Pincus beneficially own approximately 32.2% of our outstanding common stock. Accordingly, Warburg Pincus can exert significant influence over us and any action requiring the approval of the holders of our stock, including the election of directors and approval of significant corporate transactions. Warburg’s concentrated ownership makes it less likely that any other holder or group of holders of common stock will be able to affect the way we are managed or the direction of our business. These factors also may delay or prevent a change in our management or voting control.

 
Furthermore, conflicts of interest could arise in the future between us, on the one hand, and Warburg Pincus and its affiliates, on the other hand, concerning among other things, potential competitive business activities, business opportunities, the issuance of additional securities, the payment of dividends by us and other matters. Warburg Pincus is a private equity firm that has invested, among other things, in companies in the energy industry. As a result, Warburg Pincus’ existing and future portfolio companies which it controls may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor.
 
In our amended and restated certificate of incorporation, we have renounced business opportunities that may be pursued by the Partnership or by affiliated stockholders that currently hold a significant amount of our common stock.

In our restated charter and in accordance with Delaware law, we have renounced any interest or expectancy we may have in, or being offered an opportunity to participate in, any business opportunities, including any opportunities within those classes of opportunity currently pursued by the Partnership, presented to Warburg Pincus or any private fund that it manages or advises, their affiliates (other than us and our subsidiaries), their officers, directors, partners, employees or other agents who serve as one of our directors, Merrill Lynch Ventures L.P. 2001, its affiliates (other than us and our subsidiaries) and any portfolio company in which such entities or persons has an equity investment (other than us and our subsidiaries) participates or desires or seeks to participate in and that involves any aspect of the energy business or industry.

The duties of our officers and directors may conflict with those owed to the Partnership and these officers and directors may face conflicts of interest in the allocation of administrative time among our business and the Partnership’s business.

We anticipate that substantially all of our officers and certain members of our board of directors will be officers or directors of the General Partner and, as a result, will have separate duties that govern their management of the Partnership’s business. These officers and directors may encounter situations in which their obligations to us, on the one hand, and the Partnership, on the other hand, are in conflict. The resolution of these conflicts may not always be in our best interest or that of our stockholders.

In addition, our officers who also serve as officers of the General Partner may face conflicts in allocating their time spent on our behalf and on behalf of the Partnership. These time allocations may adversely affect our or the Partnership’s results of operations, cash flows, and financial condition.

Risks Inherent in the Partnership’s Business

Because we are directly dependent on the distributions we receive from the Partnership, risks to the Partnership’s operations are also risks to us. We have set forth below risks to the Partnership’s business and operations, the occurrence of which could negatively impact the Partnership’s financial performance and decrease the amount of cash it is able to distribute to us.

The Partnership has a substantial amount of indebtedness which may adversely affect its financial position.

The Partnership has a substantial amount of indebtedness. As of December 31, 2010, the Partnership had approximately $765.3 million of borrowings outstanding under its senior secured credit facility, approximately $101.3 million of letters of credit outstanding and approximately $233.4 million of additional borrowing capacity under its senior secured credit facility. The partnership’s $1.1 billion senior secured revolving credit facility allows us to request increases in commitments up to an additional $300.0 million. For the years ended December 31, 2010, 2009 and 2008, the Partnership’s consolidated interest expense was $110.8 million, $159.8 million and $156.1 million.

This substantial level of indebtedness increases the possibility that the Partnership may be unable to generate cash sufficient to pay, when due, the principal of, interest on or other amounts due in respect of indebtedness. This substantial indebtedness, combined with the Partnership’s lease and other financial obligations and contractual commitments, could have other important consequences to us, including the following:

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the Partnership’s ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

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satisfying the Partnership’s obligations with respect to indebtedness may be more difficult and any failure to comply with the obligations of any debt instruments could result in an event of default under the agreements governing such indebtedness;

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the Partnership will need a portion of cash flow to make interest payments on debt, reducing the funds that would otherwise be available for operations and future business opportunities;

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the Partnership’s debt level will make it more vulnerable to competitive pressures or a downturn in its business or the economy generally; and

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the Partnership’s debt level may limit flexibility in planning for, or responding to, changing business and economic conditions.

The Partnership’s ability to service its debt will depend upon, among other things, its 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 its control. If the Partnership’s operating results are not sufficient to service its current or future indebtedness, it will be forced to take actions such as reducing or delaying business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital and may adversely affect the Partnership’s ability to make cash distributions. The Partnership may not be able to affect any of these actions on satisfactory terms, or at all.

Increases in interest rates could adversely affect the Partnership’s business.

The Partnership has significant exposure to increases in interest rates. As of December 31, 2010, its total indebtedness was $1,445.4 million, of which $680.1 million was at fixed interest rates and $765.3 million was at variable interest rates. After giving effect to interest rate swaps with a notional amount of $300 million, a one percentage point increase in the interest rate on the Partnership’s variable interest rate debt would have increased its consolidated annual interest expense by approximately $4.7 million. As a result of this significant amount of variable interest rate debt, the Partnership’s financial condition could be adversely affected by significant increases in interest rates.

 
Despite current indebtedness levels, the Partnership may still be able to incur substantially more debt. This could increase the risks associated with its substantial leverage.

The Partnership may be able to incur substantial additional indebtedness in the future. As of December 31, 2010, the Partnership had approximately $765.3 million of borrowings outstanding under its senior secured credit facility, approximately $101.3 million of letters of credit outstanding and approximately $233.4 million of additional borrowing capacity under its senior secured credit facility. The Partnership may be able to incur an additional $300 million of debt under its senior secured credit facility if it requests and is able to obtain commitments for the additional $300 million available under its senior secured credit facility. Although the Partnership’s senior secured credit facility contains restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of significant qualifications and exceptions, and any indebtedness incurred in compliance with these restrictions could be substantial. If the Partnership incurs additional debt, the risks associated with its substantial leverage would increase.
 
The terms of the Partnership’s senior secured credit facility and indentures may restrict its current and future operations, particularly its ability to respond to changes in business or to take certain actions.

The credit agreement governing the Partnership’s senior secured credit facility and the indentures governing the Partnership’s senior notes (other than its 11¼% senior notes due 2017) contain, and any future indebtedness the Partnership incurs will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on its ability to engage in acts that may be in its best long-term interests. These agreements include covenants that, among other things, restrict the Partnership’s ability to:

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incur or guarantee additional indebtedness or issue preferred stock;

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pay distributions on its equity securities or redeem, repurchase or retire its equity securities or subordinated indebtedness;

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make investments;

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create restrictions on the payment of distributions to its equity holders;

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sell assets, including equity securities of its subsidiaries;

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engage in affiliate transactions,

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consolidate or merge;

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incur liens;

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prepay, redeem and repurchase certain debt, other than loans under the senior secured credit facility;

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make certain acquisitions;

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transfer assets;

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enter into sale and lease back transactions;

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make capital expenditures;

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amend debt and other material agreements; and

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change business activities conducted by it.

In addition, the Partnership’s senior secured credit facility requires it to satisfy and maintain specified financial ratios and other financial condition tests. The Partnership’s ability to meet those financial ratios and tests can be affected by events beyond its control, and we cannot assure you that the Partnership will meet those ratios and tests.

A breach of any of these covenants could result in an event of default under the Partnership’s senior secured credit facility and indentures, as applicable. Upon the occurrence of such an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If the Partnership is unable to repay the accelerated debt under its senior secured credit facility, the lenders under senior secured credit facility could proceed against the collateral granted to them to secure that indebtedness. The Partnership has pledged substantially all of its assets as collateral under its senior secured credit facility. If the Partnership indebtedness under its senior secured credit facility or indentures is accelerated, we cannot assure you that the Partnership will have sufficient assets to repay the indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements may adversely affect the Partnership’s ability to finance future operations or capital needs or to engage in other business activities.

 
The Partnership’s 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 its results of operations and financial condition.

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

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the impact of seasonality and weather;

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general economic conditions and economic conditions impacting the Partnership’s primary markets;

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the economic conditions of the Partnership’s customers;

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

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

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actions taken by foreign oil and gas producing nations;

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

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

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the impact of energy conservation efforts; and

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the extent of governmental regulation and taxation.

The Partnership’s primary natural gas gathering and processing arrangements that expose it to commodity price risk are its percent-of-proceeds arrangements. For the year ended December 31, 2010 and 2009, its percent-of-proceeds arrangements accounted for approximately 37% and 48% of its gathered natural gas volume. Under these arrangements, the Partnership generally processes natural gas from producers and remits 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 its processing facilities.  In some percent-of-proceeds arrangements, the Partnership remits to the producer a percentage of an 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, the Partnership’s revenues and its cash flows increase or decrease, whichever is applicable, as the price of natural gas, NGLs and crude oil fluctuates. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures about Market Risk.”


Because of the natural decline in production in the Partnership’s operating regions and in other regions from which it sources NGL supplies, the Partnership’s long-term success depends on its ability to obtain new sources of supplies of natural gas and NGLs, which depends on certain factors beyond its control. Any decrease in supplies of natural gas or NGLs could adversely affect the Partnership’s business and operating results.

The Partnership’s gathering systems are connected to oil and natural gas wells from which production will naturally decline over time, which means that its cash flows associated with these sources of natural gas will likely also decline over time. The Partnership’s logistics assets are similarly impacted by declines in NGL supplies in the regions in which the Partnership operates as well as other regions from which it sources NGLs. To maintain or increase throughput levels on its gathering systems and the utilization rate at its processing plants and its treating and fractionation facilities, the Partnership must continually obtain new natural gas and NGL supplies. A material decrease in natural gas production from producing areas on which the Partnership relies, as a result of depressed commodity prices or otherwise, could result in a decline in the volume of natural gas that it processes and NGL products delivered to its fractionation facilities. The Partnership’s ability to obtain additional sources of natural gas and NGLs depends, in part, on the level of successful drilling and production activity near its gathering systems and, in part, on the level of successful drilling and production in other areas from which it sources NGL supplies. The Partnership has no control over the level of such activity in the areas of its operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, the Partnership has 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 historically volatile, and the Partnership expects this volatility to continue. Consequently, even if new natural gas reserves are discovered in areas served by the Partnership’s 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 the Partnership operates may prevent it from obtaining supplies of natural gas to replace the natural decline in volumes from existing wells, which could result in reduced volumes through its facilities, and reduced utilization of its gathering, treating, processing and fractionation assets.

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

The Partnership’s ability to grow depends, in part, on its ability to make acquisitions that result in an increase in cash generated from operations per unit. The Partnership is unable to acquire businesses from us in order to grow because our only assets are the interests in the Partnership that we own. As a result, it will need to focus on third-party acquisitions and organic growth. If the Partnership is unable to make these accretive acquisitions either because the Partnership is (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 its future growth and ability to increase distributions will be limited.

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

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operating a significantly larger combined organization and adding operations;

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

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

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

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the failure to realize any expected synergies and cost savings;

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coordinating geographically disparate organizations, systems and facilities.

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the assumption of unknown liabilities;

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limitations on rights to indemnity from the seller;

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inaccurate assumptions about the overall costs of equity or debt;

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

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customer or key employee losses at the acquired businesses.

If these risks materialize, the acquired assets may inhibit the Partnership’s growth, fail to deliver expected benefits and add further unexpected costs. Challenges may arise whenever businesses with different operations or management are combined and the Partnership may experience unanticipated delays in realizing the benefits of an acquisition. If the Partnership consummates any future acquisition, its 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 the Partnership will consider in evaluating future acquisitions.

The Partnership’s acquisition strategy is based, in part, on its expectation of ongoing divestitures of energy assets by industry participants. A material decrease in such divestitures would limit its opportunities for future acquisitions and could adversely affect its operations and cash flows available for distribution to its unit holders.

Acquisitions may significantly increase the Partnership’s size and diversify the geographic areas in which it operates. The Partnership may not achieve the desired affect from any future acquisitions.

The Partnership’s 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 its results of operations and financial condition.

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

 
The Partnership’s acquisition strategy requires access to new capital. Tightened capital markets or increased competition for investment opportunities could impair its ability to grow through acquisitions.

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

In addition, the Partnership is experiencing increased competition for the types of assets it contemplates purchasing. Weak economic conditions and competition for asset purchases could limit the Partnership’s ability to fully execute its growth strategy.

Demand for propane is seasonal and requires increases in the partnership’s inventory to meet seasonal demand.

Weather conditions have a significant impact on the demand for propane because end-users depend on propane principally for heating purposes. Warmer-than-normal temperatures in one or more regions in which the Partnership operates can significantly decrease the total volume of propane it sells. Lack of consumer demand for propane may also adversely affect the retailers the Partnership transacts within its wholesale propane marketing operations, exposing it to their inability to satisfy their contractual obligations to the Partnership.

If the Partnership fails to balance its purchases of natural gas and its sales of residue gas and NGLs, its exposure to commodity price risk will increase.

The Partnership may not be successful in balancing its purchases of natural gas and its sales of residue gas and NGLs. In addition, a producer could fail to deliver promised volumes to the Partnership 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 the Partnership’s purchases and sales. If the Partnership’s purchases and sales are not balanced, it will face increased exposure to commodity price risks and could have increased volatility in its operating income.

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

The Partnership has entered into derivative transactions related to only a portion of its equity volumes. As a result, it will continue to have direct commodity price risk to the unhedged portion. The Partnership’s actual future volumes may be significantly higher or lower than it estimated at the time it entered into the derivative transactions for that period. If the actual amount is higher than it estimated, it will have greater commodity price risk than it intended. If the actual amount is lower than the amount that is subject to its derivative financial instruments, it might be forced to satisfy all or a portion of its derivative transactions without the benefit of the cash flow from its sale of the underlying physical commodity. The percentages of the Partnership’s expected equity volumes that are covered by its hedges decrease over time. To the extent the Partnership hedges its commodity price risk, it may forego the benefits it would otherwise experience if commodity prices were to change in its favor. The derivative instruments the Partnership utilizes 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 it realizes in its operations. These pricing differentials may be substantial and could materially impact the prices the Partnership ultimately realizes.  In addition, current market and economic conditions may adversely affect the Partnership’s hedge counterparties’ ability to meet their obligations. Given the current volatility in the financial and commodity markets, the Partnership may experience defaults by its hedge counterparties in the future. As a result of these and other factors, the Partnership’s hedging activities may not be as effective as it intends in reducing the variability of its cash flows, and in certain circumstances may actually increase the variability of its cash flows. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures about Market Risk.”

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

The Partnership depends upon third-party pipelines, storage and other facilities that provide delivery options to and from its pipelines and processing facilities. Since it does not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within the Partnership’s control. If any of these third-party facilities become partially or fully unavailable, or if the quality specifications for their facilities change so as to restrict the Partnership’s ability to utilize them, its revenues could be adversely affected.

The Partnership’s industry is highly competitive, and increased competitive pressure could adversely affect the Partnership’s business and operating results.

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

The Partnership typically does not obtain independent evaluations of natural gas reserves dedicated to its gathering pipeline systems; therefore, volumes of natural gas on the Partnership’s systems in the future could be less than it anticipates.

The Partnership typically does not obtain independent evaluations of natural gas reserves connected to its gathering systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, the Partnership does not have independent estimates of total reserves dedicated to its gathering systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to its gathering systems is less than it anticipates and the Partnership is unable to secure additional sources of natural gas, then the volumes of natural gas transported on its gathering systems in the future could be less than it anticipates. A decline in the volumes of natural gas on the Partnership’s systems could have a material adverse effect on its business, results of operations, and financial condition.

 
A reduction in demand for NGL products by the petrochemical, refining or other industries or by the fuel markets, or a significant increase in NGL product supply relative to this demand, could materially adversely affect the Partnership’s business, results of operations and financial condition.

The NGL products the Partnership produces have a variety of applications, including as heating fuels, 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 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 the Partnership handles or reduce the fees it charges for its services. Also, increased supply of NGL products could reduce the value of NGLs handled by the Partnership and reduce the margins realized. The Partnership’s 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 the Partnership’s 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 mandated 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 or increased supply for ethane, propane, normal butane, isobutane or natural gasoline in the markets the Partnership’s accesses for any of the reasons stated above could adversely affect demand for the services it provides as well as NGL prices, which would negatively impact the Partnership’s results of operations and financial condition.

The Partnership has significant relationships with Chevron Phillips Chemical Company LLC as a customer for its marketing and refinery services. In some cases, these agreements are subject to renegotiation and termination rights.

For the years ended December 31, 2010, and 2009, approximately 10% and 15% of the Partnership’s consolidated revenues were derived from transactions with CPC. Under many of the Partnership’s CPC contracts where it purchases or markets NGLs on CPC’s behalf, CPC may elect to terminate the contracts or renegotiate the price terms. To the extent CPC reduces the volumes of NGLs that it purchases from the Partnership or reduces the volumes of NGLs that the Partnership markets on its behalf or to the extent the economic terms of such contracts are changed, the Partnership’s revenues and cash available for debt service could decline.

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

We currently own an approximate 13.7% limited partner interest, a 2% general partner interest and the IDRs in the Partnership. The anticipated after-tax economic benefit of our investment in the Partnership depends largely on its being treated as a partnership for federal income tax purposes. In order to maintain its status as a partnership for United States federal income tax purposes, 90 percent or more of the gross income of the Partnership for every taxable year must be “qualifying income” under section 7704 of the Internal Revenue Code of 1986, as amended. The Partnership has not requested and does not plan to request a ruling from the IRS with respect to its treatment as a partnership for federal income tax purposes. Despite the fact that the Partnership is a limited partnership under Delaware law, it is possible, under certain circumstances for an entity such as the Partnership to be treated as a corporation for federal income tax purposes.

Although the Partnership does not believe based upon its current operations that it is so treated, a change in the Partnership’s business could cause it to be treated as a corporation for federal income tax purposes or otherwise subject it to federal income taxation as an entity. If the Partnership were treated as a corporation for federal income tax purposes, it would pay federal income tax on its 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 the Partnership’s unitholders, including us, would generally be taxed again as corporate distributions and no income, gains, losses or deductions would flow through to the Partnership’s unitholders, including us. If such tax was imposed upon the Partnership as a corporation, its cash available for distribution would be substantially reduced. Therefore, treatment of the Partnership as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the Partnership’s unitholders, including us, and would likely cause a substantial reduction in the value of our investment in the Partnership.

In addition, current law may change so as to cause the Partnership to be treated as a corporation for federal income tax purposes or otherwise subject the Partnership to entity-level taxation for state or local income tax purposes. At the federal level, members of Congress have recently considered legislative changes that would affect the tax treatment of certain publicly traded partnerships. Although the considered legislation would not appear to have affected the Partnership’s treatment as a partnership, we are unable to predict whether any of these changes or other proposals will be reintroduced or 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 the Partnership’s 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, the Partnership is required to pay Texas franchise tax at a maximum effective rate of 0.7% of its gross income apportioned to Texas in the prior year. Imposition of any similar tax on the Partnership by additional states would reduce the cash available for distribution to Partnership unitholders, including us.

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

 
The Partnership does not own most of the land on which its pipelines and compression facilities are located, which could disrupt its operations.

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

The Partnership may be unable to cause its majority-owned joint ventures to take or not to take certain actions unless some or all of its joint venture participants agree.

The Partnership participates in several majority-owned joint ventures whose corporate governance structures require at least a majority in interest vote to authorize many basic activities and require a greater voting interest (sometimes up to 100%) to authorize more significant activities. Examples of these more significant activities are large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital, making distributions, transactions with affiliates of a joint venture participant, litigation and transactions not in the ordinary course of business, among others. Without the concurrence of joint venture participants with enough voting interests, the Partnership may be unable to cause any of its joint ventures to take or not take certain actions, even though taking or preventing those actions may be in the best interest of the Partnership or the particular joint venture.

In addition, subject to certain conditions, any joint venture owner may sell, transfer or otherwise modify its ownership interest in a joint venture, whether in a transaction involving third parties or the other joint owners. Any such transaction could result in the Partnership partnering with different or additional parties.


Weather may limit the Partnership’s ability to operate its business and could adversely affect its operating results.

The weather in the areas in which the Partnership operates can cause disruptions and in some cases suspension of its operations. For example, unseasonably wet weather, extended periods of below freezing weather or hurricanes may cause disruptions or suspensions of the Partnership’s operations, which could adversely affect its operating results.

The Partnership’s business involves many hazards and operational risks, some of which may not be insured or fully covered by insurance. If a significant accident or event occurs that is not fully insured, if the Partnership fails to recover all anticipated insurance proceeds for significant accidents or events for which it is insured, or if it fails to rebuild facilities damaged by such accidents or events, its operations and financial results could be adversely affected.

The Partnership’s operations are subject to many hazards inherent in gathering, compressing, treating, processing and selling natural gas and the storing, fractionation, treating, transportation and selling of NGLs, including:

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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;

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

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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

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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 the Partnership’s related operations. A natural disaster or other hazard affecting the areas in which the Partnership operates could have a material adverse effect on its operations. For example, Hurricanes Katrina and Rita damaged gathering systems, processing facilities, NGL fractionators and pipelines along the Gulf Coast, including certain of the Partnership’s facilities. These hurricanes disrupted the operations of the Partnership’s 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.  The Partnership is not fully insured against all risks inherent to its business. The Partnership is 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 the Partnership fails to recover all anticipated insurance proceeds for significant accidents or events for which it is insured, or if it fails to rebuild facilities damaged by such accidents or events, its operations and financial condition could be adversely affected. In addition, the Partnership may not be able to maintain or obtain insurance of the type and amount it desires at reasonable rates. As a result of market conditions, premiums and deductibles for certain of the Partnership’s 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 were generally less favorable than terms that could be obtained prior to such hurricanes. Insurance market conditions worsened as a result of the losses sustained from Hurricanes Gustav and Ike in September 2008. As a result, the Partnership experienced further increases in deductibles and premiums, and further reductions in coverage and limits, with some coverages unavailable at any cost.

 
The Partnership 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 Inspection, Protection, Enforcement and Safety Act of 2006, the DOT, through the PHMSA, has adopted regulations requiring pipeline operators to develop integrity management programs for transmission pipelines 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:

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perform ongoing assessments of pipeline integrity;

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

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improve data collection, integration and analysis;

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repair and remediate the pipeline as necessary; and

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implement preventive and mitigating actions.

In addition, states have adopted regulations similar to existing DOT regulations for intrastate gathering and transmission lines. The Partnership currently estimates that it will incur an aggregate cost of approximately $6.6 million between 2011 and 2012 to implement pipeline integrity management program testing along certain segments of its 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, the Partnership cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, 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.  The Partnership will continue its pipeline integrity testing programs to assess and maintain the integrity of its pipelines. The results of these tests could cause the Partnership to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operations of its pipelines.

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

The Partnership sells processed natural gas to third parties at plant tailgates or at pipeline pooling points. Sales made to natural gas marketers and end-users may be interrupted by disruptions to volumes anywhere along the system. The Partnership attempts to balance sales with volumes supplied from processing operations, but unexpected volume variations due to production variability or to gathering, plant or pipeline system disruptions may expose the Partnership to volume imbalances which, in conjunction with movements in commodity prices, could materially impact the Partnership’s income from operations and cash flow.

The Partnership requires a significant amount of cash to service its indebtedness. The Partnership’s ability to generate cash depends on many factors beyond its control.

The Partnership’s ability to make payments on and to refinance its indebtedness and to fund planned capital expenditures depends on its ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond its control. We cannot assure you that the Partnership will generate sufficient cash flow from operations or that future borrowings will be available to it under its credit agreement or otherwise in an amount sufficient to enable it to pay its indebtedness or to fund its other liquidity needs. The Partnership may need to refinance all or a portion of its indebtedness at or before maturity. The Partnership cannot assure you that it will be able to refinance any of its indebtedness on commercially reasonable terms or at all.

Failure to comply with existing or new environmental laws or regulations or an accidental release of hazardous substances, hydrocarbons or wastes into the environment may cause the Partnership to incur significant costs and liabilities.

The Partnership’s 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. 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, as amended, (“RCRA”) and comparable state laws that impose requirements for the handling, storage, treatment or disposal of solid and hazardous waste from the Partnership’s facilities, (3) the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, (“CERCLA” or the “Superfund” law) 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 the Partnership’s hazardous substances have been transported for recycling or disposal and (4) the Clean Water Act and comparable state laws that regulate discharges of wastewater from the Partnership’s 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 or other sanctions, the imposition of remedial obligations 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, hydrocarbons or waste products have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by noise, odor or the release of hazardous substances, hydrocarbons or waste products into the environment.

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

Moreover, stricter laws, regulations or enforcement policies could significantly increase the Partnership’s operational or compliance costs and the cost of any remediation that may become necessary. For instance, since August 2009, the Texas Commission on Environmental Quality (“TCEQ”) has conducted a comprehensive analysis of air emissions in the Barnett Shale area in response to reported concerns about high concentrations of benzene in the air near drilling sites and natural gas processing facilities. Partially in response to its investigation, the TCEQ has proposed new air permitting requirements for oil and gas facilities in the state, which will first become applicable to facilities located in the Barnett Shale area on April 1, 2011. These new requirements could require the Partnership to incur increased capital or operating costs. Moreover, the agency’s investigations could lead to additional, more stringent air permitting requirements, increased regulation, and possible enforcement actions against producers and midstream operators in the Barnett Shale area.  The Partnership is also conducting its own evaluation of air emissions at certain of its facilities in the Barnett Shale area and, as necessary, plans to conduct corrective actions at such facilities. Additionally, environmental groups have advocated increased regulation and a moratorium on the issuance of drilling permits for new natural gas wells in the Barnett Shale area. The adoption of any laws, regulations or other legally enforceable mandates that result in more stringent air emission limitations or that restrict or prohibit the drilling of new natural gas wells for any extended period of time could increase the Partnership’s operating and compliance costs as well as reduce the rate of production of natural gas operators with whom the Partnership has a business relationship, which could have a material adverse effect on the Partnership’s results of operations and cash flows.

 
Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact the Partnership’s revenues by decreasing the volumes of natural gas that the Partnership gathers, processes and fractionates.

Hydraulic fracturing is a process used by oil and gas exploration and production operators in the completion of certain oil and gas wells whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate gas and, to a lesser extent, oil production.  The process is typically regulated by state oil and gas commissions.  However, the U.S. Environmental Protection Agency (“EPA”) recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s (“SDWA”) Underground Injection Control Program.  While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision.  At the same time, the EPA has commenced a study of the potential adverse impact of hydraulic fracturing activities, with results of the study expected to be available in late 2012, and a committee of the U.S. House of Representatives is conducting an investigation of hydraulic fracturing practices.  Also, legislation was introduced in the recently completed session of Congress to amend the SDWA to subject hydraulic fracturing operations to regulation under the Act and to require the disclosure of chemicals used by the oil and natural gas industry, and such legislation could be introduced in the current session of Congress.  Moreover, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. Adoption of legislation or of any implementing regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of natural gas and, in turn, adversely affect the Partnership’s revenues and results of operations by decreasing the volumes of natural gas that it gathers, processes and fractionates.

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

Venice Gathering System, L.L.C. (“VGS”) is a wholly owned subsidiary of VESCO engaged in the business of transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of FERC under the NGA. VGS owns and operates a natural gas gathering system extending from South Timbalier Block 135 to an onshore interconnection to a natural gas processing plant owned by VESCO. With the exception of our interest in VGS, our operations are generally exempt from FERC regulation under the NGA, but FERC regulation still affects our non-FERC jurisdictional businesses and the markets for products derived from these businesses. The NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. The Partnership believes that the natural gas pipelines in its 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 the Partnership’s gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. In addition, the courts have determined that certain pipelines that would otherwise be subject to the ICA are exempt from regulation by FERC under the ICA as proprietary lines. The classification of a line as a proprietary line is a fact-based determination subject to FERC and court review. Accordingly, the classification and regulation of some of the Partnership’s gathering facilities and transportation pipelines may be subject to change based on future determinations by FERC, the courts, or Congress.

While the Partnerships’ natural gas gathering operations are generally exempt from FERC regulation under the NGA, its gas gathering operations may be subject to certain FERC reporting and posting requirements in a given year. FERC has issued a final rule (as amended by orders on rehearing and clarification), 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.  It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704.  Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting.

In addition, FERC has issued a final rule, (as amended by orders on rehearing and clarification), 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/d and requiring interstate pipelines to post information regarding the provision of no-notice service. The Partnership takes the position that at this time it and its subsidiaries are exempt from this rule.  A petition for review of Order 720 is currently pending before the Court of Appeals for the Fifth Circuit, and the Partnership has no way to predict with certainty whether and to what extent Order 720 will be modified in response to the petition for review.

In addition, FERC recently issued an order extending certain of the open-access requirements including the prohibition on buy/sell arrangements and shipper-must-have-title provisions to include Hinshaw pipelines to the extent such pipelines provide interstate service. However, FERC issued a Notice of Inquiry on October 21, 2010, effectively suspending the recent ruling and requesting comments on whether and how holders of firm capacity on Section 311 and Hinshaw pipelines should be permitted to allow others to make use of their firm interstate capacity, including to what extent buy/sell transactions should be permitted.

Other FERC regulations may indirectly impact the Partnership’s 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 the Partnership fail to comply with all applicable FERC administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines.

Under the Domenici-Barton Energy Policy Act of 2005 (“EP Act 2005”), which is applicable to VGS, 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 the Partnership’s systems have not been regulated by FERC as a natural gas companies under the NGA, FERC has adopted regulations that may subject certain of its 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 the Partnership to civil penalty liability. For more information regarding regulation of Targa’s operations, see “Item 1. Business—Regulation of Operations.”

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

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.  Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act.  The EPA recently adopted two sets of rules regulating GHG emissions under the Clean Air Act, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources, effective January 2, 2011.  The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing, or requiring state environmental agencies to implement, the rules.  The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities on an annual basis, beginning in 2012 for emissions occurring in 2011.

In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs.  Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances.  The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal.  The adoption of legislation or regulatory programs to reduce emissions of GHGs could require the Partnership to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements.  Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the natural gas and NGLs the Partnership processes or fractionates.  Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on the Partnership’s business, financial condition and results of operations.  Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events.  If any such effects were to occur, they could have an adverse effect on the Partnership’s financial condition and results of operations.

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on the Partnership’s ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with its business.

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Partnership, that participate in that market. The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was signed into law by the President on July 21, 2010, and requires the CFTC and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the Act, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize these regulations. The financial reform legislation may also require the Partnership to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities, although the application of those provisions to the Partnership is uncertain at this time. The financial reform legislation may also require counterparties to the Partnership’s derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect the Partnership’s available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Partnership encounters, reduce the Partnership’s ability to monetize or restructure its existing derivative contracts, and increase the Partnership’s exposure to less creditworthy counterparties. If the Partnership reduces its use of derivatives as a result of the legislation and regulations, its results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect its ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. The Partnership’s revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on the Partnership, its financial condition, and its results of operations.

The Partnership’s interstate common carrier liquids pipeline is regulated by the Federal Energy Regulatory Commission.

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

Recent events in the Gulf of Mexico may adversely affect the operations of the Partnership.

On April 20, 2010, the Transocean Deepwater Horizon drilling rig exploded and subsequently sank 130 miles south of New Orleans, Louisiana, and the resulting release of crude oil into the Gulf of Mexico was declared a Spill of National Significance by the United States Department of Homeland Security. The Partnership cannot predict with any certainty the impact of this oil spill, the extent of cleanup activities associated with this spill, or possible changes in laws or regulations that may be enacted in response to this spill, but this event and its aftermath could adversely affect the Partnership’s operations. It is possible that the direct results of the spill and clean-up efforts could interrupt certain offshore production processed by our facilities. Furthermore, additional governmental regulation of, or delays in issuance of permits for, the offshore exploration and production industry may negatively impact current or future volumes being gathered or processed by the Partnership’s facilities, and may potentially reduce volumes in its Downstream logistics and marketing business.

Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to the Partnership’s business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact the Partnership’s 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 the Partnership’s industry in general and on it in particular is not known at this time. However, resulting regulatory requirements and/or related business decisions associated with security are likely to increase the Partnership’s costs.

Increased security measures taken by the Partnership as a precaution against possible terrorist attacks have resulted in increased costs to its business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect the Partnership’s operations in unpredictable ways, including disruptions of crude oil supplies and markets for its products, and the possibility that infrastructure facilities could be direct targets, 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 the Partnership to obtain. Moreover, the insurance that may be available to the Partnership may be significantly more expensive than its existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect the Partnership’s ability to raise capital.

 
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 filed suit in the 333rd District Court of Harris County, Texas against several defendants, including Targa and two 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 SAOU 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. In October 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s claims. In February 2010, the 14th Court of Appeals affirmed the District Court’s final judgment in favor of defendants in its entirety. In January 2011, the Texas Supreme Court denied the WTG’s petition for review of the lower courts’ judgment and WTG filed a motion for rehearing with the Texas Supreme Court requesting the court reconsider its denial to review WTG’s appeal. We have agreed to indemnify the Partnership for any claim or liability arising out of the WTG suit.

Except as provided above, neither we nor the Partnership is a party to any other legal proceedings other than legal proceedings arising in the ordinary course of our business. The Partnership is 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. Removed and Reserved
 
 
PART II

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

Market Information

Our common stock has been listed on the New York Stock Exchange since December 7, 2010 under the symbol “TRGP.” The following table sets forth the high and low sales prices of the common stock, as reported by The New York Stock Exchange (“NYSE”) through December 31, 2010.

 
 
Stock Prices
   
Dividends
 
Quarter Ended
High
 
Low
   
Declared
 
December 31, 2010
  $ 28.40     $ 23.50     $ 0.06  

As of February 22, 2011, there were approximately 224 stockholders of record of our common stock. This number does not include stockholders whose shares are held in trust by other entities. The actual number of stockholders is greater than the number of holders of record.

Overview of Distributions
 
During the past three fiscal years, our stockholders have received dividends from us on a pro rata basis. Holders of our previously outstanding preferred stock received their pro rata share of (i) an $18 million dividend paid on November 22, 2010; (ii) a $220 million extraordinary dividend paid in April 2010; (iii) a $200 million extraordinary dividend paid on the common stock (treating the preferred stock on a common stock equivalent basis) in April 2010; and (iv) a $445 million dividend paid in 2007. Holders of our common stock received their pro rata share of the $200 million extraordinary dividend paid in April 2010 (treating the preferred stock on a common stock equivalent basis).

Our Dividend Policy

We intend to pay to our stockholders, on a quarterly basis, dividends equal to the cash we receive from our Partnership distributions, less reserves for expenses, future dividends and other uses of cash, including:

·  
Federal income taxes, which we are required to pay because we are taxed as a corporation;
 
·  
the expenses of being a public company;
 
·  
other general and administrative expenses;
 
·  
general and administrative reimbursements to the Partnership;
 
·  
capital contributions to the Partnership upon the issuance by it of additional partnership securities if we choose to maintain the General Partner’s 2.0% interest;
 
·  
reserves our board of directors believes prudent to maintain;
 
·  
our obligation to (i) satisfy tax obligations associated with previous sales of assets to the Partnership, (ii) reimburse the Partnership for certain capital expenditures related to Versado and (iii) provide the Partnership with limited quarterly distribution support through 2011, all as described in more detail in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources;” and
 
·  
interest expense or principal payments on any indebtedness we incur.
 
On February 21, 2011, we paid a cash dividend of $0.0616 per share of common stock, or $2.6 million in total, to holders of our outstanding common stock. This dividend was pro-rated to give effect to a partial quarter following our IPO. If the Partnership is successful in implementing its business strategy and increasing distributions to its partners, we would generally expect to increase dividends to our stockholders, although the timing and amount of any such increased dividends will not necessarily be comparable to the increased Partnership distributions. We cannot assure you that any dividends will be declared or paid in the future.
 
The determination of the amount of cash dividends, including the quarterly dividend referred to above, if any, to be declared and paid will depend upon our financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects and any other matters that our board of directors deems relevant. The Partnership’s debt agreements contain restrictions on the payment of distributions and prohibit the payment of distributions if the Partnership is in default. If the Partnership cannot make incentive distributions to the general partner or limited partner distributions to us, we will be unable to pay dividends on our common stock.
 
 
The Partnership’s Cash Distribution Policy
 
Under the Partnership’s partnership agreement, available cash is defined to generally mean, for each fiscal quarter, all cash on hand at the date of determination of available cash for that quarter less the amount of cash reserves established by the General Partner to provide for the proper conduct of the Partnership’s business, to comply with applicable law or any agreement binding on the Partnership and its subsidiaries and to provide for future distributions to the Partnership’s unitholders for any one or more of the upcoming four quarters. The determination of available cash takes into account the possibility of establishing cash reserves in some quarterly periods that the Partnership may use to pay cash distributions in other quarterly periods, thereby enabling it to maintain relatively consistent cash distribution levels even if the Partnership’s business experiences fluctuations in its cash from operations due to seasonal and cyclical factors. The General Partner’s determination of available cash also allows the Partnership to maintain reserves to provide funding for its growth opportunities. The Partnership makes its quarterly distributions from cash generated from its operations, and those distributions have grown over time as its business has grown, primarily as a result of numerous acquisitions and organic expansion projects that have been funded through external financing sources and cash from operations.
 
The actual cash distributions paid by the Partnership to its partners occur within 45 days after the end of each quarter. Since second quarter 2007, the Partnership has increased its quarterly cash distribution 7 times. During that time period, the Partnership has increased its quarterly distribution by 62% from $0.3375 per common unit, or $1.35 on an annualized basis, to $0.5475 per common unit, or $2.19 on an annualized basis.

Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Credit Facilities and Long-Term Debt” and Note 9 to our consolidated financial statements for a discussion of restrictions on our and our subsidiaries’ ability to pay dividends or make distributions.

Recent Sales of Unregistered Stock

None

Repurchase of Equity by Targa Resources Corp.

None
 
 
Item 6. Selected Financial Data

The following table presents selected historical consolidated financial and operating data of Targa Resources Corp. for the periods and as of the dates indicated. We derived this information from our historical consolidated financial statements and accompanying notes.  This information should be read together with, and is qualified in its entirety, by reference to those financial statements and notes, which for the years 2010, 2009 and 2008 begins on page F-1 of this Form 10-K.

  
 
Year Ended December 31,
 
  
 
2010
   
2009
   
2008
   
2007
   
2006
 
  
 
(In millions, except per share amounts)
 
Revenues(1)
  $ 5,469.2     $ 4,536.0     $ 7,998.9     $ 7,297.2     $ 6,132.9  
Income from operations 
    196.1       217.2       234.5       280.3       237.1  
Net income 
    63.3       79.1       134.4       104.2       50.2  
Net income (loss) attributable to Targa Resources Corp. 
    (15.0 )     29.3       37.3       56.1       24.2  
Dividends on Series B preferred stock 
    (9.5 )     (17.8 )     (16.8 )     (31.6 )     (39.7 )
Net income (loss) available to common shareholders 
    (202.3 )     -       -       -       (15.5 )
Net loss per common share - Basic and diluted 
    (30.94 )     -       -       -       (2.53 )
Balance Sheet Data (at end of period) 
                                       
Total assets 
  $ 3,393.8     $ 3,367.5     $ 3,641.8     $ 3,795.1     $ 3,458.0  
Long-term debt 
    1,534.7       1,593.5       1,976.5       1,867.8       1,471.9  
Convertible cumulative participating Series B 
                                       
preferred stock 
    -       308.4       290.6       273.8       687.2  
Total owners' equity 
    1,036.1       754.9       822.0       574.1       (71.5 )
Other: 
                                       
Dividends declared per share 
  $ 0.0616    
NA
   
NA
   
NA
   
NA
 
Dividends paid on Series B preferred shares 
  $ 238.0     $ -     $ -     $ 445.1     $ -  
 
_________
(1)  
Includes business interruption insurance revenues of $6.0 million, $21.5 million, $32.9 million, and $7.3 million, for the years ended 2010, 2009, 2008 and 2007. We received no business interruption proceeds during 2006.

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

The following discusses and analyzes our financial condition and results of operations. You should read the following discussion in conjunction with our historical financial statements and notes included in Part IV of this Annual Report. Also, the Partnership files a separate Annual Report on Form 10-K with the SEC.

Overview

Financial Presentation

An indirect subsidiary of ours is the sole member of the General Partner. Because we control the General Partner, under generally accepted accounting principles we must reflect our ownership interest in the Partnership on a consolidated basis. Accordingly, our financial results are combined with the Partnership’s financial results in our consolidated financial statements even though the distribution or transfer of Partnership assets are limited by the terms of the partnership agreement, as well as restrictive covenants in the Partnership’s lending agreements. The limited partner interests in the Partnership not owned by us are reflected in our results of operations as net income attributable to non-controlling interests. Therefore, throughout this discussion, we make a distinction where relevant between financial results of the Partnership versus those of us as a standalone parent including our non-Partnership subsidiaries.

The Partnership is a leading provider of midstream natural gas and NGL services in the United States. The Partnership is engaged in the business of gathering, compressing, treating, processing and selling natural gas and storing, fractionating, treating, transporting and selling NGLs and NGL products. It operates through two divisions: the Natural Gas Gathering and Processing division and the NGL Logistics and Marketing division.

As a result of the conveyance of all of our remaining operating assets to the Partnership in September 2010, we have no separate, direct operating activities apart from those conducted by the Partnership. As such, our cash inflows will primarily consist of cash distributions from our interests in the Partnership. The Partnership is required to distribute all available cash at the end of each quarter after establishing reserves to provide for the proper conduct of its business or to provide for future distributions.

The Partnership files its own separate Annual Report. The results of operations included in our consolidated financial statements will differ from the results of operations of the Partnership primarily due to the financial effects of: non-controlling interests in the Partnership, our separate debt obligations, certain general and administrative costs applicable to us as a separate public company, and certain non-operating assets and liabilities that we retained and were not included in the asset conveyances to the Partnership.

 
Factors That Significantly Affect Our Results

Our cash flow and resulting ability to pay dividends will be dependent upon the Partnership’s ability to make distributions to its partners, including us. The actual amount of cash that the Partnership will have available for distributions will depend primarily on the amount of cash that it generates from its operations.

As of February 25, 2011, our interests in the Partnership consist of the following:

·  
a 2% general partner interest, which we hold through our 100% ownership interest in the general partner of the Partnership;

·  
all IDRs; and

·  
11,645,659 of the 84,756,009 outstanding common units of the Partnership, representing a 13.7% limited partnership interest.

Cash Distributions

The following table sets forth the historical distributions that the Partnership has paid in respect of our 2% general partner interest, the associated IDRs and actual common units that we held during the periods indicated. The amount of these Partnership distributions available for distribution to us and the Partnership’s shareholders will be after reserves are established for the Partnership’s capital contributions, debt service requirements, general, administrative and other expenses, future distributions and other miscellaneous uses of cash.

               
Actual Cash Distributions
 
   
Cash
   
Limited
                           
Distributions
 
   
Distribution
   
Partner
   
Total
   
Limited
   
General
         
to Targa
 
   
Per Limited
   
Units
         
Partners
   
Partner
         
Resources
 
   
Partner Unit
   
Outstanding
         
Units
   
Interest
   
IDRs
   
Corp. (1)
 
         
(In millions, except per unit amounts)
 
2010 
                                         
Fourth Quarter
  $ 0.54750       75.5     $ 53.5     $ 46.4     $ 1.1     $ 6.0     $ 13.4  
Third Quarter
    0.53750       75.5       46.1       40.6       0.9       4.6       11.8  
Second Quarter
    0.52750       68.0       40.2       35.9       0.8       3.5       10.4  
First Quarter
    0.51750       68.0       38.8       35.2       0.8       2.8       9.6  
                                                         
2009 
                                                       
Fourth Quarter
  $ 0.51750       68.0     $ 38.8     $ 35.2     $ 0.8     $ 2.8     $ 14.0  
Third Quarter
    0.51750       61.6       35.2       31.9       0.7       2.6       13.7  
Second Quarter
    0.51750       46.2       26.4       23.9       0.5       2.0       8.5  
First Quarter
    0.51750       46.2       26.3       23.9       0.5       1.9       8.4  
                                                         
2008 
                                                       
Fourth Quarter
  $ 0.51750       46.2     $ 26.4     $ 24.0     $ 0.5     $ 1.9     $ 8.4  
Third Quarter
    0.51750       46.2       26.3       23.9       0.5       1.9       8.4  
Second Quarter
    0.51250       46.2       25.9       23.7       0.5       1.7       8.2  
First Quarter
    0.41750       46.2       19.9       19.3       0.4       0.2       5.5  
                                                         
2007 
                                                       
Fourth Quarter
  $ 0.39750       46.2     $ 18.9     $ 18.4     $ 0.4     $ 0.1     $ 5.1  
Third Quarter
    0.33750       44.4       15.3       15.0       0.3       -       4.2  
Second Quarter
    0.33750       30.9       10.6       10.4       0.2       -       4.1  
First Quarter
    0.16875       30.9       5.3       5.2       0.1       -       2.1  
 
________
(1)  
Distributions to Targa are comprised of amounts attributable to Targa’s (i) Limited Partner Units, (ii) General Partner Units, and (iii) IDRs.

 
Factors That Significantly Affect the Partnership’s Results

The Partnership’s results of operations are substantially impacted by the volumes that move through its gathering and processing and logistics assets, its contract terms and changes in commodity prices.

Volumes. In the Partnership’s gathering and processing operations, plant inlet volumes and capacity utilization rates generally are driven by wellhead production, its competitive and contractual position on a regional basis and more broadly by the impact of prices for oil, natural gas and NGLs on exploration and production activity in the areas of its operations. The factors that impact the gathering and processing volumes also impact the total volumes that flow to the Partnership’s Downstream Business. In addition, fractionation volumes are also affected by the location of the resulting mixed NGLs, available pipeline capacity to transport NGLs to the Partnership’s fractionators, and the Partnership’s competitive and contractual position relative to other fractionators.


Contract Terms and Contract Mix and the Impact of Commodity Prices. Because of the significant volatility of natural gas and NGL prices, the contract mix of the Partnership’s natural gas gathering and processing segment can also have a significant impact on its profitability, especially those that create exposure to changes in energy prices. Set forth below is a table summarizing the contract mix of the Partnership’s natural gas gathering and processing division for 2010 and the potential impacts of commodity prices on operating margins:

 
 
 
Percent of
 
 
 
Contract Type
 
Throughput
 
Impact of Commodity Prices
 
Percent-of-Proceeds/Percent-of-Liquids
 
38%
 
Decreases in natural gas and or NGL prices generate decreases in operating margins.
 
Fee-Based
 
7%
 
No direct impact from commodity price movements
 
Wellhead Purchases/Keep-whole
 
17%
 
Increases in natural gas prices relative to NGL prices generate decreases in operating margin.
 
Hybrid
 
38%
 
In periods of favorable processing economics (1), similar to percent-of-liquids or to wellhead purchases/keep-whole in some circumstances, if economically advantageous to the processor.  In periods of unfavorable processing economics, similar to fee-based.
 
______
(1)  
Favorable processing economics typically occur when processed NGLs can be sold, after allowing for processing costs, at a higher value than natural gas on a Btu equivalent basis.

The Partnership generally prefers to enter into contracts with less commodity price sensitivity including fee-based and percent-of-proceeds arrangements. However, negotiated contract terms are based upon a variety of factors, including natural gas quality, geographic location, the competitive commodity and pricing environment at the time the contract is executed, and customer requirements. The gathering and processing contract mix and, accordingly, the 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, the Partnership’s expansion into regions where different types of contracts are more common as well as other market factors.

The contract terms and contract mix of the Downstream Business can also have a significant impact on its results of operations. During periods of low relative demand for available fractionation capacity, rates were low and take-or-pay contracts were not readily available. Currently, demand for fractionation services is relatively high, rates have increased, contract terms or lengths have increased and reservation fees are required. These fractionation contracts in the logistics assets segment are primarily fee-based arrangements while the marketing and distribution segment includes both fee-based and percent-of-proceeds contracts.

Impact of the Partnership’s Commodity Price Hedging Activities. In an effort to reduce the variability of its cash flows, the Partnership has hedged the commodity price associated with a portion of its expected natural gas, NGL and condensate equity volumes through 2014 by entering into derivative financial instruments including swaps and purchased puts (or floors). With these arrangements, the Partnership has attempted to mitigate its exposure to commodity price movements with respect to its forecasted volumes for these periods. The Partnership actively manages the Downstream Business product inventory and other working capital levels to reduce exposure to changing NGL prices. For additional information regarding the Partnership’s hedging activities, see “Quantitative and Qualitative Disclosures About Market Risk— Commodity Price Risk.”

General Trends and Outlook

We expect the midstream energy business environment to continue to be affected by the following key trends: demand for our services, significant relationships, commodity prices, volatile capital markets and increased regulation. These 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.

Demand for Services. Fluctuations in energy prices can affect production rates and investments by third parties in the development of oil and natural gas reserves. Generally, drilling and production activity will increase as energy prices increase. We believe that the current strength of oil, condensate and NGL prices compared to natural gas prices has caused producers in and around the Partnership’s natural gas gathering and processing areas of operation to focus their drilling programs on regions rich in liquid forms of hydrocarbons. This focus is reflected in increased drilling permits and higher rig counts in these areas, and we expect these activities to lead to higher inlet volumes in the Field Gathering and Processing segment over the next several years. Producer activity in areas rich in oil, condensate and NGLs is currently generating increased demand for the Partnership’s fractionation services and for related fee-based services provided by its Downstream Business. While we expect development activity to remain robust with respect to oil and liquids rich gas development and production, currently depressed natural gas prices have resulted in reduced activity levels surrounding comparatively dry natural gas reserves, whether conventional or unconventional.

 
Significant Relationships. The following table lists the counterparties that account for more than 10% of the Partnership’s consolidated sales and consolidated product purchases.

 
 
 
Year Ended December 31,
 
 
 
2010 
 
2009