ETE-12.31.2011-10K
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2011
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-32740
ENERGY TRANSFER EQUITY, L.P.
(Exact name of registrant as specified in its charter)
Delaware
  
30-0108820
(State or other jurisdiction of incorporation or organization)
  
(I.R.S. Employer Identification No.)
3738 Oak Lawn Avenue, Dallas, Texas 75219
(Address of principal executive offices) (zip code)
Registrant’s telephone number, including area code: (214) 981-0700
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
  
Name of each exchange on which registered
Common Units
  
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  ý    No  ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes  ¨    No  ý
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  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes  ý    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer  ý    Accelerated filer  ¨    Non-accelerated filer  ¨    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  ý
The aggregate market value as of June 30, 2011, of the registrant’s Common Units held by non-affiliates of the registrant, based on the reported closing price of such Common Units on the New York Stock Exchange on such date, was $5.60 billion. Common Units held by each executive officer and director and by each person who owns 5% or more of the outstanding Common Units have been excluded in that such persons may be deemed to be affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.
At February 15, 2012, the registrant had 222,973,448 Common Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE
None


Table of Contents

TABLE OF CONTENTS
 
 
 
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ITEM 1.
 
 
 
ITEM 1A.
 
 
 
ITEM 1B.
 
 
 
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ITEM 7A.
 
 
 
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ITEM 9B.
 
 
 
 
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PART I
Forward-Looking Statements
Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Equity, L.P. (“Energy Transfer Equity,” the “Partnership” or “ETE”) in periodic press releases and some oral statements of the Partnership’s officials during presentations about the Partnership, include forward-looking statements. These “forward-looking” statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “continue,” “could,” “believe,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its General Partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from those anticipated, estimated, projected or expected in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Item 1.A Risk Factors” included in this annual report.
Definitions
The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:
 
 
/d
  
per day
 
 
 
 
Bbls
  
barrels
 
 
 
 
Btu
  
British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy content
 
 
 
 
Capacity
  
capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels
 
 
 
 
Mcf
  
thousand cubic feet
 
 
 
 
MMBtu
  
million British thermal units
 
 
 
 
MMcf
  
million cubic feet
 
 
 
 
Bcf
  
billion cubic feet
 
 
 
 
NGL
  
natural gas liquid, such as propane, butane and natural gasoline
 
 
 
 
Tcf
  
trillion cubic feet
 
 
 
 
LIBOR
  
London Interbank Offered Rate
 
 
 
 
NYMEX
  
New York Mercantile Exchange
 
 
 
 
Reservoir
  
a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers
 
 
 
 
WTI
  
West Texas Intermediate Crude



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ITEM 1.  BUSINESS
Overview
We were formed in September 2002 and completed our initial public offering in February 2006. We are a Delaware limited partnership with common units publicly traded on the New York Stock Exchange (“NYSE”) under the ticker symbol “ETE.”
Unless the context requires otherwise, references to “we,” “us,” “our,” “the Partnership” and “ETE” shall mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. (“ETP”); Energy Transfer Partners GP, L.P. (“ETP GP”), the general partner of ETP; Energy Transfer Partners, L.L.C. (“ETP LLC”), ETP GP’s general partner; Regency Energy Partners LP (“Regency”); Regency GP LP (“Regency GP”), the general partner of Regency; and Regency GP LLC (“Regency LLC”), Regency GP’s general partner. References to the “Parent Company” shall mean ETE on a stand-alone basis.
Currently, the Parent Company’s only cash generating assets are its direct and indirect investments in limited partner and general partner interests in ETP and Regency, both of which are publicly traded master limited partnerships engaged in diversified energy-related services.
At December 31, 2011, our interests in ETP and Regency consisted of:
 
 
General Partner
Interest (as a %
of total
partnership
interest)
 
Incentive
Distribution
Rights
(“IDRs”)
 
Limited
Partner Units
ETP
1.5
%
 
100
%
 
50,226,967

Regency
1.8
%
 
100
%
 
26,266,791

We acquired our equity interests in Regency in a series of transactions, which we refer to as the “Regency Transactions,” that were completed on May 26, 2010. In the Regency Transactions, the Parent Company:
acquired the general partner interest and IDRs in Regency in exchange for 3,000,000 Series A Convertible preferred units (“the Preferred Units”) having an aggregate liquidation preference of $300 million;
acquired from ETP an indirect 49.9% interest in Midcontinent Express Pipeline LLC (“MEP”), ETP’s joint venture with Kinder Morgan Energy Partners, L.P. (“KMP”) to operate the Midcontinent Express Pipeline, and an option to acquire an additional 0.1% interest in MEP in exchange for the redemption by ETP of approximately 12.3 million ETP Common Units we previously owned; and,
acquired 26.3 million Regency Common Units in exchange for our contribution to Regency of all interests in MEP acquired by the Parent Company from ETP, including the option to acquire an additional 0.1% interest.
The Parent Company’s primary cash requirements are for distributions to its partners and holders of the Preferred Units, general and administrative expenses, debt service requirements and at ETE’s election, capital contributions to ETP and Regency in respect of ETE’s general partner interests in ETP and Regency. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of ETP, Regency or their respective subsidiaries.
The following is a brief description of ETP’s and Regency’s operations:
ETP is a publicly traded partnership owning and operating a diversified portfolio of energy assets. ETP has pipeline operations in Arizona, Arkansas, Colorado, Louisiana, New Mexico, Utah and West Virginia and owns the largest intrastate pipeline system in Texas. ETP currently has natural gas operations that include more than 17, 500 miles of gathering and transportation pipelines, treating and processing assets, and three storage facilities located in Texas. ETP also holds a 70% membership interest in Lone Star NGL LLC (“Lone Star”), a joint venture that owns and operates NGL storage, fractionation and transportation assets in Texas, Louisiana and Mississippi.
Regency is a publicly traded partnership engaged in the gathering and processing, contract compression, treating and transportation of natural gas and the transportation, fractionation and storage of NGLs. Regency focuses on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Bone Spring and Avalon Shales, as well as the Permian Delaware basin. Its assets are primarily located in Texas, Louisiana, Arkansas, Pennsylvania, California, Mississippi, Alabama, West Virginia and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% membership interest in Lone Star.

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In order to fully understand the financial condition and results of operations of the Parent Company on a stand-alone basis, we have included herein discussions of Parent Company matters apart from those of our consolidated group.
Organizational Structure
The following chart summarizes our organizational structure as of December 31, 2011:

Recent Developments
Pending Acquisition
On July 19, 2011, we entered into a transaction to acquire Southern Union Company (“SUG”), a Delaware corporation. This transaction, which we refer to as the SUG Merger, will provide us with direct ownership of assets that are complementary to the assets owned and operated by ETP and Regency. To execute the SUG Merger, we entered into a Second Amended and Restated Plan of Merger (the “SUG Merger Agreement”) with Sigma Acquisition Corporation, a Delaware corporation and our wholly-

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owned subsidiary (“Merger Sub”), and SUG. The Second Amended Merger Agreement modifies certain terms of the Amended and Restated Agreement and Plan of Merger entered into by us, Merger Sub and SUG on July 4, 2011. Under the terms of the SUG Merger Agreement, Merger Sub will merge with and into SUG, with SUG continuing as the surviving entity and becoming our wholly-owned subsidiary subject to certain conditions to close. Pursuant to the SUG Merger Agreement, we would acquire all of the outstanding shares of SUG in a transaction valued at $9.4 billion, including $5.7 billion in cash and ETE Common Units and $3.7 billion of existing SUG indebtedness. Stockholders of SUG may elect to exchange each share of SUG stock for either $44.25 in cash or 1.00 ETE Common Unit. The maximum cash component is 60% of the aggregate consideration and the common unit component can fluctuate between 40% and 50%. Elections in excess of either the cash or common unit limits will be subject to proration.
We have secured $3.7 billion in committed financing from a group of lenders led by Credit Suisse Securities (USA) LLC to fund a portion of the cash consideration related to the SUG Merger. On December 9, 2011, the special meeting of the SUG stockholders was held and the SUG stockholders voted to approve the SUG Merger. ETE and SUG have made filings with the Missouri Public Service Commission and expect to receive its approval of the SUG Merger in the first quarter of 2012. Closing of this business combination is contingent upon several conditions, including regulatory approvals and we expect the transaction to close in the first quarter of 2012.
On July 19, 2011, ETP entered into an Amended Citrus Merger Agreement pursuant to which it is anticipated that SUG will cause the contribution to ETP of SUG’s 50% interest in Citrus Corp., which owns 100% of the Florida Gas Transmission (“FGT”) pipeline system, in exchange for approximately $1.895 billion in cash and $105 million of ETP Common Units, contemporaneous with the completion of the merger between SUG and us pursuant to the Second Amended SUG Merger Agreement. Citrus Corp is currently jointly owned by SUG and El Paso Corporation. The FGT pipeline system has a capacity of 3.0 billion cubic feet per day. FGT’s primary customers are utilities with strong investment grade credit ratings; FGT’s long-term contracts with these high credit quality customers are expected to increase ETP’s fee-based revenue stream.
Propane Operations
On January 12, 2012, ETP contributed its propane operations, consisting of Heritage Operating, L.P. (“HOLP”) and Titan Energy Partners, L.P. (“Titan”) (collectively, the “Propane Business”), to AmeriGas Partners, L.P. (“AmeriGas”). ETP received $1.46 billion in cash and approximately 29.6 million AmeriGas common units in consideration for the contribution of the Propane Business, plus the assumption by AmeriGas of approximately $71 million of existing HOLP debt. This transaction improved ETP's liquidity and allows ETP to focus on its core business in the natural gas and NGL markets. As a result of this transaction, we have not included a discussion of ETP's propane assets or operations in Item 1.
Growth Projects
ETP, Regency and Lone Star's aggregate growth capital expenditures for 2011 were $1.8 billion. In 2012, ETP, Regency and Lone Star expect their aggregate capital expenditures to be between $2.6 billion and $2.9 billion, which includes additional NGL assets including construction of a NGL fractionator at Mont Belvieu, assets in the Eagle Ford Shale, assets in the Woodford and Barnett Shales, in addition to various other growth projects. In addition to these capital expenditures, ETP expects to complete its acquisition of a 50% interest in Citrus in conjunction with our acquisition of SUG, as described above. Along with the inherent benefits of greater scale and cash flow diversification that we experience from growth and acquisitions that occur at ETP and Regency, we also expect to directly benefit through increases in the distributions that we receive through our limited partner, general partner and IDR interests in ETP and Regency.
Ranch Joint Venture
On December 2, 2011, Ranch Westex JV LLC (“Ranch JV”) was formed by Regency, Anadarko Pecos Midstream LLC and Chesapeake West Texas Processing, L.L.C., each owning 33.33% of the joint venture. Ranch JV, upon completion of construction in 2012, will process natural gas delivered from the NGL-rich Bone Spring and Avalon shale formations in West Texas. The project consists of two plants, a 25 MMcf/d refrigeration plant and a 100 MMcf/d cryogenic processing plant. The initial start-up of the refrigeration unit is expected to be in service by the second quarter of 2012, with full facilities available by the fourth quarter of 2012.
Business Strategy
Our current primary business objective is to increase cash available for distributions by actively assisting ETP and Regency in executing their business strategies by assisting in identifying, evaluating and pursuing strategic acquisitions and growth opportunities. In general, we expect that we will allow ETP or Regency the first opportunity to pursue any acquisition or internal growth project that may be presented to us which may be within the scope of ETP and Regency’s operations or business strategies. In the future, we may also support the growth of ETP and Regency through the use of our capital resources which could involve

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loans, capital contributions or other forms of credit support to ETP and Regency. This funding could be used for the acquisition by ETP or Regency of a business or asset or for an internal growth project. In addition, the availability of this capital could assist ETP or Regency in arranging financing for a project, reducing its financing costs or otherwise supporting a merger or acquisition transaction.
Segment Overview
Our reportable segments consist of our investment in ETP and our investment in Regency. The businesses within these two segments are described below. See Note 14 to our consolidated financial statements for additional financial information about our reportable segments.
Investment in ETP
ETP’s operations include the following:
Intrastate Transportation and Storage Operations
Through ETP’s intrastate transportation and storage operations, it owns and operates approximately 8,300 miles of natural gas transportation pipelines and three natural gas storage facilities located in the state of Texas.
Through Energy Transfer Company (“ETC OLP”), ETP owns the largest intrastate pipeline system in the United States with interconnects to Texas markets and to major consumption areas throughout the United States. ETP’s intrastate transportation and storage operations focuses on the transportation of natural gas to major markets from various prolific natural gas producing areas through connections with other pipeline systems as well as through ETP’s Oasis pipeline, its East Texas pipeline, its natural gas pipeline and storage assets that ETP refers to as the ET Fuel System, and its HPL System, which are described below.
ETP’s intrastate transportation and storage operations are determined primarily by the amount of capacity its customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, ETP’s customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly.
ETP also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on its HPL System. Generally, ETP purchases natural gas from either the market (including purchases from ETP’s midstream marketing operations) or from producers at the wellhead. To the extent the natural gas comes from producers, it is primarily purchased at a discount to a specified market price and typically resold to customers based on an index price. In addition, ETP’s intrastate transportation and storage operations generate revenues from fees charged for storing customers’ working natural gas in its storage facilities and from margin from managing natural gas for ETP’s own account. The major customers on ETP's intrastate pipelines include Natural Gas Exchange, Inc., EDF Trading North America, Inc., XTO Energy, Inc. and ConocoPhillips.
Interstate Transportation Operations
Through ETP’s interstate transportation operations, it owns and operates approximately 2,880 miles of interstate natural gas pipeline and has a 50% interest in the joint venture that owns the 185-mile Fayetteville Express pipeline.
The results from its interstate transportation operations are primarily derived from the fees ETP earns from natural gas transportation services and, for the Transwestern pipeline, from operational gas sales. The major customers on ETP's interstate pipelines include
Chesapeake Energy Marketing, Inc., EnCana Marketing (USA), Inc. (“EnCana”), Shell Energy North America (US), L.P. and Pacific Summit Energy LLC.
Midstream Operations
Through ETP’s midstream operations, it owns and operates approximately 7,400 miles of in-service natural gas gathering pipelines, two natural gas processing plants, 15 natural gas treating facilities and 11 natural gas conditioning facilities. ETP’s midstream operations focuses on the gathering, compression, treating, blending, processing and marketing of natural gas, and its operations are currently concentrated in major producing basins and shales, including the Austin Chalk trend and Eagle Ford Shale in South and Southeast Texas, the Permian Basin in West Texas and New Mexico, the Barnett Shale in North Texas, the Bossier Sands in East Texas, and the Uinta and Piceance Basins in Utah and Colorado, the Marcellus Shale in West Virginia, and the Haynesville Shale in East Texas and Louisiana. Many of ETP’s midstream assets are integrated with its intrastate transportation and storage assets.

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ETP’s midstream operations results are derived primarily from margins ETP earns for natural gas volumes that are gathered, transported, purchased and sold through its pipeline systems and the natural gas and NGL volumes processed at its processing and treating facilities. ETP also markets natural gas on its pipeline systems in addition to other pipeline systems to realize incremental revenue on gas purchased, increase pipeline utilization and provide other services that are valued by its customers. The major customers on ETP's midstream pipelines include Enterprise Products Partners L.P. ("Enterprise") and Chevron Phillips Chemical Company LP.
NGL Transportation and Services Operations
Through ETP's NGL transportation and services operations, it owns and operates an approximately 45-mile NGL pipeline and have a 50% interest in the Liberty pipeline, an approximately 85-mile NGL pipeline. ETP also has a 70% interest in the Lone Star joint venture that owns approximately 1,400 miles of NGL pipelines, three processing plants, one fractionation facility and NGL storage facilities with aggregate working storage capacity of 47 million Bbls. ETP's NGL transportation and services operations, which was created through the acquisition of LDH in May 2011.
NGL transportation revenue is principally generated from fees charged to customers under dedicated contracts or take-or-pay contracts. Under a dedicated contract, the customer agrees to deliver the total output from particular processing plants that are connected to the NGL pipeline. Take-or-pay contracts have minimum throughput commitments requiring the customer to pay regardless of whether a fixed volume is transported. Transportation fees are market-based, negotiated with customers and competitive with regional regulated pipelines.
NGL storage revenues are derived from base storage fees and throughput fees. Base storage fees are based on the volume of capacity reserved, regardless of the capacity actually used. Throughput fees are charged for providing ancillary services, including receipt and delivery, custody transfer, rail/truck loading and unloading fees. Storage contracts may be for dedicated storage or fungible storage. Dedicated storage enables a customer to reserve an entire storage cavern, which allows the customer to inject and withdraw proprietary and often unique products. Fungible storage allows a customer to store specified quantities of NGL products that are commingled in a storage cavern with other customers’ products of the same type and grade. NGL storage contracts may be entered into on a firm or interruptible basis. Under a firm basis contract, the customer obtains the right to store products in the storage caverns throughout the term of the contract; whereas, under an interruptible basis contract, the customer receives only limited assurance regarding the availability of capacity in the storage caverns.
These operations also include revenues earned from processing and fractionating refinery off-gas. Under these contracts ETP receives an Olefins-grade ("O-grade") stream from cryogenic processing plants located at refineries and fractionate the products into their pure components. ETP delivers purity products to customers through pipelines and across a truck rack located at the fractionation complex. In addition to revenues for fractionating the O-grade stream, ETP has percent-of-proceeds and income sharing contracts, which are subject to market pricing of olefins and NGLs. For percent-of-proceeds contracts, ETP retains a portion of the purity NGLs and olefins processed, or a portion of the proceeds from the sales of those commodities, as a fee. When NGLs and olefin prices increase, the value of the portion ETP retains as a fee increases. Conversely, when NGLs and olefin prices decrease, so does the value of the portion ETP retains as a fee. Under ETP's income sharing contracts, it pays the producer the equivalent energy value for their liquids, similar to a traditional keep-whole processing agreement, and then share in the residual income created by the difference between NGLs and olefin prices as compared to natural gas prices. As NGLs and olefins prices increase in relation to natural gas prices, the value of the percent ETP retains as a fee increases. Conversely, when NGLs and olefins prices decrease as compared to natural gas prices, so does the value of the percent it retains as a fee. The major customers on our NGL pipelines include Targa Resources Partners LP, The Williams Companies, Inc. and Louis Dreyfus Highbridge Energy LLC.
Retail Propane Operations
As discussed above, in January 2012 ETP contributed its propane operations to AmeriGas. See further discussion of this transaction in “Recent Developments” above.
All Other
ETP’s other operations include wholesale propane and natural gas compression services.

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Investment in Regency
Regency’s operations include the following:
Gathering, Treating and Processing Operations
Regency provides “wellhead-to-market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs and selling or delivering the pipeline-quality natural gas and NGLs to various markets and pipeline systems.
Joint Ventures Operations
Regency owns four investments in joint ventures. See a description of its investments in joint ventures under “Asset Overview – Investment in Regency – Joint Ventures Operations.”
Contract Compression Operations
Regency owns and operates a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems.
Contract Treating Operations
Regency owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management, to natural gas producers and midstream pipeline companies.
Other Operations
Regency also owns a small regulated pipeline.
Asset Overview
Investment in ETP
The following details the assets in ETP’s operations:
Intrastate Transportation and Storage Operations
The following details ETP’s pipelines and storage facilities in its intrastate transportation and storage operations.
ET Fuel System
Capacity of 5.2 Bcf/d
Approximately 2,950 miles of natural gas pipeline
Two storage facilities with 12.4 Bcf of total working gas capacity
Bi-directional capabilities
The ET Fuel System serves some of the most active drilling areas in the United States and is comprised of intrastate natural gas pipeline and related natural gas storage facilities. With approximately 560 receipt and/or delivery points, including interconnects with pipelines providing direct access to power plants and interconnects with other intrastate and interstate pipelines, the ET Fuel System is strategically located near high-growth production areas and provides access to the Waha Hub near Midland, Texas, the Katy Hub near Houston, Texas and the Carthage Hub in East Texas, the three major natural gas trading centers in Texas. The major shippers on its pipelines include EOG Resources, Inc., Chesapeake Energy Marketing, Inc., XTO Energy, Inc. (“XTO”), Luminant Energy Company LLC and Encana.
The ET Fuel System also includes ETP’s Bethel natural gas storage facility, with a working capacity of 6.4 Bcf, an average withdrawal capacity of 300 MMcf/d and an injection capacity of 75 MMcf/d, and its Bryson natural gas storage facility, with a working capacity of 6.0 Bcf, an average withdrawal capacity of 120 MMcf/d and an average injection capacity of 96 MMcf/d. All of ETP’s storage capacity on the ET Fuel System is contracted to third parties under fee-based arrangements that expire in 2012 and 2013.
In addition, the ET Fuel System is integrated with ETP’s Godley processing plant which gives ETP the ability to bypass the plant when processing margins are unfavorable by blending the untreated natural gas from the North Texas System with natural gas on the ET Fuel System while continuing to meet pipeline quality specifications.

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Oasis Pipeline
Capacity of 1.2 Bcf/d
Approximately 600 miles of natural gas pipeline
Connects Waha to Katy market hubs
The Oasis pipeline is primarily a 36-inch natural gas pipeline. It has bi-directional capability with approximately 1.2 Bcf/d of throughput capacity moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis pipeline has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.
The Oasis pipeline is integrated with ETP’s Southeast Texas System and is an important component to maximizing its Southeast Texas System’s profitability. The Oasis pipeline enhances the Southeast Texas System by (i) providing access for natural gas on the Southeast Texas System to other third party supply and market points and interconnecting pipelines and (ii) allowing ETP to bypass its processing plants and treating facilities on the Southeast Texas System when processing margins are unfavorable by blending untreated natural gas from the Southeast Texas System with gas on the Oasis pipeline while continuing to meet pipeline quality specifications.
HPL System
Capacity of 5.5 Bcf/d
Approximately 4,350 miles of natural gas pipeline
Bammel storage facility with 62 Bcf of total working gas capacity
The HPL System is an extensive network of intrastate natural gas pipelines, an underground Bammel storage reservoir and related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from South Texas, the Gulf Coast of Texas, East Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City and other cities located along the Gulf Coast of Texas. The HPL System is well situated to gather and transport gas in many of the major gas producing areas in Texas including the strong presence in the key Houston Ship Channel and Katy Hub markets, allowing ETP to play an important role in the Texas natural gas markets. The HPL System also offers its shippers off-system opportunities due to its numerous interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel and Agua Dulce, and its Bammel storage facility.
The Bammel storage facility has a total working gas capacity of approximately 62 Bcf, a peak withdrawal rate of 1.3 Bcf/d and a peak injection rate of 0.6 Bcf/d. The Bammel storage facility is located near the Houston Ship Channel market area and the Katy Hub and is ideally suited to provide a physical backup for on-system and off-system customers. As of December 31, 2011, ETP had approximately 13.7 Bcf committed under fee-based arrangements with third parties and approximately 48.6 Bcf stored in the facility for its own account.
East Texas Pipeline
Capacity of 2.4 Bcf/d
Approximately 370 miles of natural gas pipeline
The East Texas pipeline connects three treating facilities, one of which ETP owns, with its Southeast Texas System. The East Texas pipeline was the first phase of a multi-phased project that increased service to producers in East and North Central Texas and provided access to the Katy Hub. The East Texas pipeline expansions include the 36-inch East Texas extension to connect its Reed compressor station in Freestone County to its Grimes County compressor station, the 36-inch Katy expansion connecting Grimes to the Katy Hub, and the 42-inch Southeast Bossier pipeline connecting its Cleburne to Carthage pipeline to the HPL System. Key shippers on the East Texas pipeline include XTO and EnCana with an average of 540,000 MMBtu/d and 200,000 MMBtu/d, respectively.
Interstate Transportation Operations
The following details ETP’s pipelines in its interstate transportation operations.
Transwestern Pipeline
Capacity of 2.1 Bcf/d
Approximately 2,690 miles of interstate natural gas pipeline
Bi-directional capabilities
The Transwestern pipeline is an open-access interstate natural gas pipeline extending from the gas producing regions of West

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Texas, eastern and northwestern New Mexico, and southern Colorado primarily to pipeline interconnects off the east end of its system and to pipeline interconnects at the California border. The Transwestern pipeline has access to three significant gas basins: the Permian Basin in West Texas and eastern New Mexico; the San Juan Basin in northwestern New Mexico and southern Colorado; and the Anadarko Basin in the Texas and Oklahoma panhandle. Natural gas sources from the San Juan Basin and surrounding producing areas can be delivered eastward to Texas intrastate and mid-continent connecting pipelines and natural gas market hubs as well as westward to markets in Arizona, Nevada and California. Transwestern’s Phoenix lateral pipeline, with a throughput capacity of 500 MMcf/d, connects the Phoenix area to the Transwestern mainline.
Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users. Transwestern transports natural gas in interstate commerce.
Tiger Pipeline
Capacity of 2.4 Bcf/d
Approximately 195 miles of interstate natural gas pipeline
Bi-directional capabilities
The Tiger pipeline is an approximately 195-mile interstate natural gas pipeline that connects to our dual 42-inch pipeline system near Carthage, Texas, extends though the heart of the Haynesville Shale and ends near Delhi, Louisiana, with interconnects to at least seven interstate pipelines at various points in Louisiana. The pipeline has a capacity of 2.4 Bcf/d, all of which is sold under long-term contracts ranging from 10 to 15 years.
Fayetteville Express Pipeline
Capacity of 2.0 Bcf/d
Approximately 185 miles of interstate natural gas pipeline
50/50 joint venture with Kinder Morgan Energy Partners, L.P. (“KMP”)
The Fayetteville Express pipeline is an approximately 185-mile interstate natural gas pipeline that originates near Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. The pipeline has long-term contracts for 1.85 Bcf/d ranging from 10 to 12 years. The Fayetteville Express pipeline is a 50/50 joint venture with KMP.
Midstream Operations
The following details ETP’s assets in its midstream operations.
Southeast Texas System
Approximately 5,540 miles of natural gas pipeline
One natural gas processing plant (the La Grange plant) with aggregate capacity of 210 MMcf/d
12 natural gas treating facilities with aggregate capacity of 1.6 Bcf/d
Four natural gas conditioning facilities with aggregate capacity of 650 MMcf/d
The Southeast Texas System is an integrated system that gathers, compresses, treats, processes and transports natural gas from the Austin Chalk trend. The La Grange processing plant also processes rich gas from the Eagle Ford Shale. The Southeast Texas System is a large natural gas gathering system covering thirteen counties between Austin and Houston. This system is connected to the Katy Hub through the East Texas pipeline and is connected to the Oasis pipeline, as well as two power plants. This allows ETP to bypass its processing plants and treating facilities when processing margins are unfavorable by blending untreated natural gas from the Southeast Texas System with natural gas on the Oasis pipeline while continuing to meet pipeline quality specifications.
The La Grange processing plant is a cryogenic natural gas processing plant that processes the rich natural gas that flows through ETP’s system to produce residue gas and NGLs.
ETP’s treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into its system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications. In addition, ETP’s conditioning facilities remove heavy hydrocarbons from the gas gathered into ETP’s systems so the gas can be redelivered and meet downstream pipeline hydrocarbon dew point specifications.

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North Texas System
Approximately 160 miles of natural gas pipeline
One natural gas processing plant (the Godley plant) with aggregate capacity of 480 MMcf/d
One natural gas conditioning facility with capacity of 100 MMcf/d
The North Texas System is an integrated system located in four counties in North Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett Shale trend. The system includes ETP’s Godley processing plant, which processes rich natural gas produced from the Barnett Shale and is integrated with the North Texas System and the ET Fuel System. The facility consists of a cryogenic processing plant and a conditioning facility.
Canyon Gathering System
Approximately 1,390 miles of natural gas pipeline
Five natural gas conditioning facilities with aggregate capacity of 96 MMcf/d
The Canyon Gathering System consists of gathering pipeline ranging in diameters from two inches to 24 inches in the Piceance and Uinta Basins of Colorado and Utah and conditioning plants.
Northern Louisiana
Approximately 240 miles of natural gas pipeline
Three natural gas treating facilities with aggregate capacity of 385 MMcf/d
ETP’s Northern Louisiana assets comprise several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with several pipelines, including ETP’s Tiger pipeline. ETP’s Northern Louisiana assets include the Bistineau, Creedence, and Tristate Systems.
Other Midstream Assets
ETP’s midstream operations also includes its interests in various midstream assets located in Texas, New Mexico and Louisiana, with gathering pipelines aggregating a combined capacity of approximately 115 MMcf/d, as well as one conditioning facility. ETP also owns gathering pipelines serving the Marcellus Shale in West Virginia with aggregate capacity of approximately 250 MMcf/d.
Marketing Operations
ETP conducts marketing operations in which it markets the natural gas that flows through its gathering and intrastate transportation assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through its assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other suppliers and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices of natural gas, less the costs of transportation.
For the off-system gas, ETP purchases gas or acts as an agent for small independent producers that may not have marketing operations. ETP develops relationships with natural gas producers to facilitate the purchase of their production on a long-term basis. ETP believes that this business provides it with strategic insight and market intelligence, which may positively impact its expansion and acquisition strategy.
NGL Transportation and Services
The following details ETP's assets in its NGL transportation and services operations. All assets described below are owned by Lone Star, in which ETP has a 70% interest.
West Texas System
Capacity of 137,000 Bbls
Approximately 1,170 miles of NGL transmission pipelines
The West Texas System is an intrastate NGL pipeline consisting of 3-inch to 16-inch long-haul, mixed NGLs transportation pipeline that delivers 137,000 Bbls of capacity from the Regency Waha Processing Plant in the Permian Basin and our Godley Processing Plant in the Barnett Shale to the Mont Belvieu NGL storage facility.

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Mont Belvieu Storage Facility
Working storage capacity of approximately 43 million Bbls
Approximately 140 miles of NGL transmission pipelines
The Mont Belvieu storage facility is an integrated liquids storage facility with over 43 million Bbls of salt dome capacity and 23 million Bbls of brine pond capacity, providing 100% fee-based cash flows. The Mont Belvieu storage facility has access to multiple NGL and refined product pipelines, the Houston Ship Channel trading hub, and numerous chemical plants, refineries and fractionators.
Hattiesburg Storage Facility
Working storage capacity of four million Bbls
The Hattiesburg storage facility is an integrated liquids storage facility with approximately four million Bbls of salt dome capacity, providing 100% fee-based cash flows.
Sea Robin Processing Plant
One cryogenic processing plant (the Chalmette Plant) with 850 MMcf/d residue capacity and 26,000 Bbls/d NGL capacity
20% non-operating interest held by Lone Star
Sea Robin is a cryogenic rich gas processing plant located on the Sea Robin Pipeline in southern Louisiana. The plant, which is connected to nine interstate and four intrastate residue pipelines as well as various deep-water production fields, has a residue capacity of 850MMcf/d and an NGL capacity of 26,000 Bbls/d.
Refinery Services
One cryogenic processing plant (the Chalmette Plant) with 54 MMcf/d capacity
One cryogenic processing plant (the Sorrento Plant) with 28 MMcf/d capacity
One NGL fractionator with 25,000 Bbls/d capacity
Approximately 100 miles of NGL pipelines
Refinery Services consists of a refinery off-gas processing and "O-grade" NGL fractionation complex located along the Mississippi River refinery corridor in southern Louisiana that cryogenically processes refinery off-gas and fractionates the Ograde NGL stream into its higher value components. The O-grade fractionator located in Geismar, Louisiana is connected by approximately 100 miles of pipeline to the Sorrento and Chalmette cryogenic processing plants.
Investment in Regency
The following details the assets in Regency’s natural gas operations:
Gathering, Treating and Processing Operations
Regency operates gathering and processing assets in four geographic regions of the United States: North Louisiana, the mid-continent region of the United States, South Texas and West Texas. Regency contracts with producers to gather raw natural gas from individual wells or central receipt points, which may have multiple wells behind them, located near its processing plants, treating facilities and/or gathering systems. Following the execution of a contract, Regency connects wells and central delivery points to its gathering lines through which the raw natural gas flows to a processing plant, treating facility or directly to interstate or intrastate gas transportation pipelines. At its processing plants and treating facilities, Regency removes impurities from the raw natural gas stream and extracts the NGLs. Regency also performs a producer service function, whereby it purchases natural gas from producers at gathering systems and plants and sells this gas at downstream outlets.
All raw natural gas flowing through Regency’s gathering and processing facilities is supplied under gathering and processing contracts having terms ranging from month-to-month to the life of the oil and gas lease.
The pipeline-quality natural gas remaining after separation of NGLs through processing is either returned to the producer or sold, for Regency’s own account or for the account of the producer, at the tailgates of Regency’s processing plants for delivery to interstate or intrastate gas transportation pipelines.

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North Louisiana Region
Approximately 442 miles of natural gas pipeline
Two cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant and two amine treating plants
Regency’s North Louisiana assets gather, compress, treat and dehydrate natural gas in five Parishes (Claiborne, Union, DeSoto, Lincoln and Ouachita) of North Louisiana and Shelby County, Texas.
Through the gathering and processing systems described above and their interconnections with HPC’s pipeline system in North Louisiana, Regency offers producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.
South Texas Region
Approximately 565 miles of natural gas pipeline
Two treating plants
Regency’s South Texas assets gather, compress, treat and dehydrate natural gas in LaSalle, Webb, Karnes, Atascosa, McMullen, Frio and Dimmitt counties. Some of the natural gas produced in this region can have significant quantities of hydrogen sulfide and carbon dioxide that require treating to remove these impurities. The pipeline systems that gather this gas are connected to third-party processing plants and Regency’s treating facilities that include an acid gas reinjection well located in McMullen County, Texas.
The natural gas supply for Regency’s South Texas gathering systems is derived from a combination of natural gas wells located in a mature basin that generally have long lives and predictable gas flow rates and the NGL-rich Eagle Ford Shale formation, which lies directly under Regency’s existing South Texas gathering system infrastructure.
One of Regency’s treating plants consists of inlet gas compression, a 60 MMcf/d amine treating unit, a 55 MMcf/d amine treating unit and a 40 ton (per day) liquid sulfur recovery unit. This plant removes hydrogen sulfide from the natural gas stream, recovers condensate, delivers pipeline quality gas at the plant outlet and reinjects acid gas. In January 2012, Regency completed an expansion of the treating plant, adding an incremental 20 MMcf/d of treating capacity to the facility.
In June 2011, Regency entered into agreements to provide gas and condensate gathering services for a producer in the Eagle Ford Shale and to construct facilities to perform these services, including a wellhead gathering system, at an expected cost of approximately $450 million. The expansion will be owned and operated by Regency and will connect with its existing gathering system. The expansion is scheduled to be completed in phases by 2014. Upon its completion, Regency's entire South Texas system will be capable of gathering, compressing, treating and transporting up to 1 Bcf/d of natural gas and 26,500 Bbls/d of condensate to downstream outlets.
Regency owns a 60% interest in an entity that includes a treating plant in Atascosa County with a 500 gallons per minute amine treater, pipeline interconnect facilities and approximately 13 miles of 10-inch pipeline. Tailsman Energy USA Inc. and Statoil Texas Onshore Properties LP own the remaining 40% interest. Regency operates this plant and the pipeline for the joint venture while its joint venture partner operates a lean gas gathering system in the Edwards Lime natural gas trend that delivers to this system.
West Texas Region
Approximately 806 miles of natural gas pipeline
One cryogenic natural gas processing plant
Regency’s West Texas gathering system assets offer wellhead-to-market services to producers in Ward, Winkler, Reeves, and Pecos counties, which surround the Waha Hub, one of Texas’ major NGL-rich natural gas market areas. As a result of the proximity of Regency’s system to the Waha Hub, the Waha gathering system has a variety of market outlets for the natural gas that Regency gathers and processes, including several major interstate pipelines serving California, the mid-continent region of the United States and Texas natural gas markets. The NGL market outlets include Lone Star's West Texas NGL pipeline.
Regency offers producers four different levels of natural gas compression on the Waha gathering system, as compared to the two levels typically offered in the industry. By offering multiple levels of compression, Regency’s gathering system is often more cost-effective for its producers, since the producer is typically not required to pay for a level of compression that is higher than the level they require.

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The Waha cryogenic natural gas processing plant processes raw natural gas gathered in the Waha gathering system. The Waha processing plant also includes an amine treating facility, which removes carbon dioxide and hydrogen sulfide from raw natural gas gathered before moving the natural gas to the processing plant. The acid gas is injected underground.
Mid-Continent Region
Approximately 3,470 miles of natural gas pipeline
One processing plant
Regency’s mid-continent assets include natural gas gathering systems located primarily in Kansas and Oklahoma. Regency’s mid-continent gathering assets are extensive systems that gather, compress and dehydrate low-pressure gas from approximately 1,500 wells. These systems are geographically concentrated, with each central facility located within 90 miles of the others. Regency operates its mid-continent gathering systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.
Regency also owns the Hugoton gathering system that has approximately 1,875 miles of pipeline extending over nine counties in Kansas and Oklahoma. This system is operated by a third party.
Regency’s mid-continent systems are located in two of the largest and most prolific natural gas producing regions in the United States, the Hugoton Basin in Southwest Kansas and the Anadarko Basin in western Oklahoma. These mature basins have continued to provide generally long-lived, predictable production volume.
Joint Ventures Operations
Regency owns four investments in joint ventures:
A 49.99% general partner interest in its RIGS Haynesville Partnership Co. joint venture (“HPC”), which owns Regency Intrastate Gas System (“RIGS”), a 450 mile intrastate pipeline that delivers natural gas from Northwest Louisiana to downstream pipelines and markets;
a 50% membership interest in Midcontinent Express Pipeline LLC (“MEP”), which owns an interstate natural gas pipeline with approximately 500 miles stretching from Southeast Oklahoma through Northeast Texas, northern Louisiana and Central Mississippi to an interconnect with the Transcontinental Gas Pipe Line system in Butler, Alabama;
a 30% membership interest in Lone Star, an entity owning a diverse set of midstream energy assets including NGL pipelines, storage, fractionation and processing facilities located in Texas, Mississippi and Louisiana; and
a 33.33% interest in Ranch JV, which, upon completion of construction in the fourth quarter of 2012, will process natural gas delivered from the NGL-rich Bone Spring and Avalon Shale formations in West Texas.
Contract Compression Operations
The natural gas contract compression operations include designing, sourcing, owning, installing, operating, servicing, repairing and maintaining compressors and related equipment for which Regency guarantees its customers 98% mechanical availability for land installations and 96% mechanical availability for over-water installations. Regency focuses on meeting the complex requirements of field-wide compression applications, as opposed to targeting the compression needs of individual wells within a field. These field-wide applications include compression for natural gas gathering and natural gas processing. Regency believes that it improves the stability of its cash flow by focusing on field-wide compression applications because such applications generally involve long-term installations of multiple large horsepower compression units. Regency’s contract compression operations are primarily located in Texas, Louisiana, Arkansas, Pennsylvania and California.
Contract Treating Operations
Regency owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and Btu management, to natural gas producers and midstream pipeline companies. Regency’s contract treating operations are primarily located in Texas, Louisiana and Arkansas.
Other Operations
Regency’s other operations comprise of a small regulated pipeline. The regulated pipeline owns and operates an interstate pipeline that consists of 10 miles of pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.

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Industry Overview
The following is a discussion of the different industries in which our subsidiaries operate. ETP and Regency both have natural gas operations.
The midstream natural gas industry is the link between the exploration and production of natural gas and the delivery of its components to end-use markets. The midstream industry consists of natural gas gathering, compression, treating, processing and transportation and NGL fractionation and transportation, and is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.
Natural gas has widely varying quality and composition, depending on the field, the formation or the reservoir from which it is produced. The principal constituents of natural gas are methane and ethane, though most natural gas also contains varying amounts of heavier components, such as propane, butane and natural gasoline that may be removed by a number of processing methods. Most raw materials produced at the wellhead are not suitable for long-haul pipeline transportation or commercial use and must be compressed, transported via pipeline to a central processing facility, and then processed to remove the heavier hydrocarbon components and other contaminants that would interfere with pipeline transportation or the end use of the gas.
Natural gas and crude oil produced at the wellhead contain varying amounts of mixed NGLs. After extraction by a processing plant the mixed NGLs are transported to a facility for fractionation into NGL products such as ethane, propane, butane, and natural gasoline. The NGL products are then delivered to end-users through pipelines, trucks, rail car and barges. End-users of NGL products include petrochemical, refining companies, and end-use propane customers.
Demand for natural gas.  Natural gas continues to be a critical component of energy consumption in the United States. According to data released in December 2010 by the Energy Information Administration, total domestic consumption of natural gas is expected to rise to 26.5 Tcf in 2035, compared to 2010 consumption of 24.1 Tcf. The industrial and electricity generation sectors currently account for more than half of natural gas usage in the United States.
Natural gas gathering.  The natural gas gathering process begins with the drilling of wells into gas-bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems generally consist of a network of small diameter pipelines and, if necessary, compression systems that collect natural gas from points near producing wells and transport it to larger pipelines for further transportation.
Natural gas compression.  Gathering systems are operated at design pressures that will maximize the total throughput from all connected wells. Specifically, lower pressure gathering systems allow wells, which produce at progressively lower field pressures as they age, to remain connected to gathering systems and to continue to produce for longer periods of time. As the pressure of a well declines, it becomes increasingly difficult to deliver the remaining production in the ground against a higher pressure that exists in the connecting gathering system. Field compression is typically used to lower the pressure of a gathering system. If field compression is not installed, then the remaining production in the ground will not be produced because it cannot overcome the higher gathering system pressure. In contrast, if field compression is installed, then a well can continue delivering production that otherwise might not be produced.
Natural gas treating.  Natural gas has a varied composition depending on the field, the formation and the reservoir from which it is produced. Natural gas from certain formations is higher in carbon dioxide, hydrogen sulfide or certain other contaminants. Treating plants remove carbon dioxide and hydrogen sulfide from natural gas to ensure that it meets pipeline quality specifications.
Natural gas processing.  Some natural gas produced by a well does not meet the pipeline quality specifications established by downstream pipelines or is not suitable for commercial use and must be processed to remove the mixed NGL stream. In addition, some natural gas produced by a well, while not required to be processed, can be processed to take advantage of favorable processing margins. Natural gas processing involves the separation of natural gas into pipeline quality natural gas, or residue gas, and a mixed NGL stream.
Natural gas transportation.  Natural gas transportation pipelines receive natural gas from other mainline transportation pipelines and gathering systems and deliver the natural gas to industrial end-users, utilities and other pipelines.
NGL transportation. NGL transportation pipelines transport mixed NGLs and other hydrocarbons from natural gas processing facilities to fractionation plants and storage facilities.
NGL storage. NGL storage facilities are used for the storage of mixed NGLs, NGL products and petrochemical products owned by third-parties in storage tanks and underground wells, which allow for the injection and withdrawal of such products at various times of the year to meet demand cycles.

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NGL Fractionation and Processing. NGL fractionators separate mixed NGL streams into purity products, such as ethane, propane, normal butane, isobutane and natural gasoline.
Competition
The business of providing natural gas gathering, compression, treating, transporting, storing and marketing services is highly competitive. Since pipelines are generally the only practical mode of transportation for natural gas over land, the most significant competitors of ETP’s and Regency’s transportation and storage operations are other pipelines. ETP and Regency also compete with each other. Pipelines typically compete with each other based on location, capacity, price and reliability.
ETP and Regency face competition with respect to retaining and obtaining significant natural gas supplies under terms favorable to them for the gathering, treating and marketing portions of their businesses. ETP’s and Regency’s competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport and market natural gas. Many of ETP’s and Regency’s competitors, such as major oil and gas and pipeline companies, have substantially greater capital resources and control of supplies of natural gas.
In markets served by ETP's and Regency's NGL pipelines, they face competition with other pipeline companies and barge, rail and truck fleet operations. ETP and Regency face competition with other storage facilities based on fees charged and their ability to receive and distribute their customer's products.
In marketing natural gas, ETP and Regency have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil companies, and local and national natural gas gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly, and through affiliates, in marketing activities that compete with ETP’s and Regency’s marketing operations.
Credit Risk and Customers
ETP and Regency maintain credit policies with regard to their counterparties that they believe significantly reduce overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty.
ETP’s and Regency’s counterparties consist primarily of petrochemical companies and other industrials, small to major oil and gas producers, midstream and power generation companies. This concentration of counterparties may impact ETP’s and Regency’s overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Currently, the management of ETP and the management of Regency do not anticipate a material adverse effect on financial position or results of operations as a result of counterparty performance. ETP and Regency are diligent in attempting to ensure that they issue credit to credit-worthy customers. However, ETP’s and Regency’s purchase and resale of gas exposes them to significant credit risk, as the margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss could be significant to ETP’s or Regency’s overall profitability.
During the year ended December 31, 2011, no individual customer accounted for more than 10% of ETE’s revenues.
Regulation
Regulation of Interstate Natural Gas Pipelines.  FERC has broad regulatory authority over the business and operations of interstate natural gas pipelines. Under the Natural Gas Act (“NGA”), FERC generally regulates the transportation of natural gas in interstate commerce. For FERC regulatory purposes, “transportation” includes natural gas pipeline transmission (forwardhauls and backhauls), storage, and other services. The Transwestern, Tiger and Gulf States pipelines transport natural gas in interstate commerce and thus qualify as a “natural gas companies” under the NGA subject to FERC’s regulatory jurisdiction. ETP also holds a joint venture interest in the Fayetteville Express pipeline and Regency owns an indirect 50% interest in the entity that owns and operates the Midcontinent Express pipeline. Both of these are NGA-jurisdictional interstate transportation systems subject to the FERC’s broad regulatory oversight.
The FERC’s NGA authority includes, among other things, the power to regulate:
the certification and construction of new facilities;
the review and approval of transportation rates;
the types of services that ETP’s and Regency’s regulated assets are permitted to perform;
the terms and conditions associated with these services;

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the extension or abandonment of services and facilities;
the maintenance of accounts and records;
the acquisition and disposition of facilities; and
the initiation and discontinuation of services.
Under the NGA, interstate natural gas companies must charge rates that are just and reasonable. In addition, the NGA prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.
Under the terms of a prior settlement, Transwestern was required to file a new NGA Section 4 general rate case no later than October 1, 2011. However, on September 2, 2011, the FERC granted Transwestern's request for an extension of the filing date until December 1, 2011. On September 21, 2011, in lieu of filing a new rate case, Transwestern filed a proposed settlement with the FERC, which was approved by the FERC on October 31, 2011. In general, the settlement provides for the continued use of Transwestern's currently effective transportation and fuel tariff rates, with the exception of certain San Juan Lateral fuel rates which will be reduced over a three year period beginning in April 2012. The settlement also resolves certain non-rate matters, and approves Transwestern's use of certain previously approved accounting methodologies. Under the settlement, Transwestern is required to file a new NGA Section 4 rate case on or before October 1, 2014.
In December 2009, the FERC issued an order granting Fayetteville Express Pipeline LLC (“FEP”) authorization to construct and operate the Fayetteville Express pipeline, subject to certain conditions, and FEP accepted the FERC’s certificate. Interim service began on the Fayetteville Express pipeline in the fourth quarter of 2010 and commenced service to all of its firm shippers on December 1, 2010, with the primary term of each firm shipper’s contract commencing by January 1, 2011. The rates charged for services on the Fayetteville Express pipeline are largely governed by long-term negotiated rate agreements. In the certificate order, the FERC also approved cost-based recourse rates available to prospective shippers as an alternative to negotiated rates.
In April 2010, the application for authority to construct the Tiger pipeline was approved by the FERC and field construction began on the pipeline in June 2010. The Tiger pipeline was placed in service on December 1, 2010. The rates charged for services on the Tiger pipeline are largely governed by long-term negotiated rate agreements. In June 2010, ETP filed an application for authority to construct and operate a 0.4 Bcf/d expansion of the Tiger pipeline with the FERC and in February 2011 ETP accepted the FERC’s certificate order authorizing the construction and operation of this expansion and the rate-related arrangements for the services to be provided on this expansion. The expansion was placed in service on August 1, 2011.
The maximum rates to be charged by NGA-jurisdictional natural gas companies and their terms and conditions for service are generally required to be on file with the FERC in FERC-approved tariffs. Most natural gas companies are authorized to offer discounts from their FERC-approved maximum just and reasonable rates when competition warrants such discounts. Natural gas companies are also generally permitted to offer negotiated rates different from rates established in their tariff if, among other requirements, such companies’ tariffs offer a cost-based recourse rate available to a prospective shipper as an alternative to the negotiated rate. Natural gas companies must make offers of rate discounts and negotiated rates on a basis that is not unduly discriminatory. Existing tariff rates may be challenged by complaint, and if found unjust and unreasonable, may be altered on a prospective basis by the FERC. ETP and Regency cannot guarantee that the FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity, transportation and storage facilities.
Pursuant to the FERC’s rules promulgated under the Energy Policy Act of 2005, it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of electric energy or natural gas or the purchase or sale of transmission or transportation services subject to FERC jurisdiction: (1) to defraud using any device, scheme or artifice; (2) to make any untrue statement of material fact or omit a material fact; or (3) to engage in any act, practice or course of business that operates or would operate as a fraud or deceit. The Commodity Futures Trading Commission (“CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act (“CEA”). With regard to ETP’s and Regency’s physical purchases and sales of natural gas, NGLs or other energy commodities; their gathering or transportation of these energy commodities; and any related hedging activities that they undertake, ETP and Regency are required to observe these anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should ETP or Regency violate the anti-market manipulation laws and regulations, they could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
Failure to comply with the NGA, the Energy Policy Act of 2005 and the other federal laws and regulations governing ETP’s and Regency’s operations and business activities can result in the imposition of administrative, civil and criminal remedies.

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Regulation of Intrastate Natural Gas and NGL Pipelines. Intrastate transportation of natural gas and NGLs is largely regulated by the state in which such transportation takes place. To the extent that ETP’s or Regency’s intrastate natural gas transportation systems transport natural gas in interstate commerce, the rates, terms and conditions of such services are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act (“NGPA”). The NGPA regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. The rates, terms and conditions of some transportation and storage services provided on the Oasis pipeline, HPL System, East Texas pipeline and ET Fuel System are subject to FERC regulation pursuant to Section 311 of the NGPA. Under Section 311, rates charged for intrastate transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The terms and conditions of service set forth in the intrastate facility’s statement of operating conditions are also subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than ETP’s or Regency’s currently approved Section 311 rates, ETP’s or Regency’s business may be adversely affected. Failure to observe the service limitations applicable to transportation and storage services under Section 311, failure to comply with the rates approved by the FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC approved statement of operating conditions could result in an alteration of jurisdictional status, and/or the imposition of administrative, civil and criminal remedies.
The FERC has adopted market-monitoring and annual reporting regulations, which regulations are applicable to many intrastate pipelines as well as other entities that are otherwise not subject to the FERC’s NGA jurisdiction such as natural gas marketers. These regulations are intended to increase the transparency of wholesale energy markets, to protect the integrity of such markets, and to improve FERC’s ability to assess market forces and detect market manipulation. The FERC has also issued regulations requiring interstate pipelines and certain major non-interstate pipelines to post, on a daily basis, capacity, scheduled flow information and actual flow information. As these posting requirements for major non-interstate pipelines have been vacated on appeal by the U.S. 5th Circuit Court of Appeals, it is not known with certainty whether and to what extent the FERC will continue to attempt to impose such posting requirements. Should the FERC succeed in reimposing these or similar regulations we could be subject to further costs and administrative burdens, none of which are expected to have a material impact on its operations.
Intrastate natural gas operations in Texas are also subject to regulation by various agencies in Texas, principally the Texas Railroad Commission (“TRRC”). ETP’s intrastate pipeline and storage operations in Texas are also subject to the Texas Utilities Code, as implemented by the TRRC. Generally, the TRRC is vested with authority to ensure that rates, operations and services of gas utilities, including intrastate pipelines, are just and reasonable and are not discriminatory. The rates charged for transportation services are deemed just and reasonable under Texas law unless challenged in a customer or TRRC complaint. We cannot predict whether such a complaint will be filed against our subsidiaries or whether the TRRC will change its regulation of these rates. Failure to comply with the Texas Utilities Code can result in the imposition of administrative, civil and criminal remedies.
Regency’s RIGS system is subject to regulation by various agencies of the State of Louisiana. Louisiana’s Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating intrastate pipelines and gathering facilities in Louisiana and has authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities. Historically, apart from pipeline safety, it has not acted to exercise this jurisdiction respecting gathering facilities. Louisiana also has agencies that regulate transportation rates, service terms and conditions and contract pricing to ensure their reasonableness and to ensure that the intrastate pipeline companies that they regulate do not discriminate among similarly situated customers.
Regulation of Sales of Natural Gas and NGLs.  The price at which ETP and Regency buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. The price at which ETP and Regency sell NGLs is not subject to federal or state regulation.
To the extent that ETP and Regency enter into transportation contracts with natural gas pipelines that are subject to FERC regulation, they are subject to FERC requirements related to use of such capacity. Any failure on ETP’s or Regency’s part to comply with the FERC’s regulations and policies, or with an interstate pipeline’s tariff, could result in the imposition of civil and criminal penalties.
ETP’s and Regency’s sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation. ETP and Regency cannot predict the ultimate impact of these regulatory changes to its natural gas marketing operations, and we note that some of the FERC’s regulatory changes may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. ETP and Regency do not believe that they will be affected by any such FERC action in a manner that is materially different from other natural gas marketers with whom they compete.

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Regulation of Gathering Pipeline.  Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. ETP owns a number of natural gas pipelines in Texas, Louisiana, Colorado, West Virginia and Utah that it believes meet the traditional tests the FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation and varying interpretations, so the classification and regulation of ETP’s gathering facilities could be subject to change based on future determinations by the FERC and the courts. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation.
In Texas, ETP’s and Regency’s gathering facilities are subject to regulation by the TRRC under the Texas Utilities Code in the same manner as described above for their intrastate pipeline facilities. Louisiana’s Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating intrastate pipelines and gathering facilities in Louisiana and has authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities.
Historically, apart from pipeline safety, Louisiana has not acted to exercise this jurisdiction respecting gathering facilities. In Louisiana, ETP’s Chalkley System is regulated as an intrastate transporter, and the Louisiana Office of Conservation has determined that its Whiskey Bay System is a gathering system.
ETP and Regency are subject to state ratable take and common purchaser statutes in all of the states in which they operate. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting the right of an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas.
Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. Many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination allegations. ETP’s and Regency’s gathering operations could be adversely affected should they be subject in the future to the application of additional or different state or federal regulation of rates and services. ETP’s and Regency’s gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. ETP and Regency cannot predict what effect, if any, such changes might have on their operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Regulation of Pipeline Safety.  ETP’s and Regency’s pipeline operations are subject to regulation by the U.S. Department of Transportation (“DOT”), under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. In addition, the states in which ETP and Regency conduct operations administer federal pipeline safety standards under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), which requires compliance with safety standards during construction and operation of certain the pipelines and subjects the pipelines to regular inspections. Failure to comply with the safety laws and regulations may result in the imposition of administrative, civil and criminal remedies. The “rural gathering exemption” under the NGPSA presently exempts substantial portions of ETP’s and Regency’s gathering facilities from jurisdiction under the NGPSA, but does not apply to intrastate natural gas pipelines. The portions of ETP’s and Regency’s facilities that are exempt include those portions located outside of cities, towns or any area designated as residential or commercial, such as a subdivision or shopping center. Changes to federal pipeline safety laws and regulations are being considered by Congress and the DOT including changes to the “rural gathering exemption,” which may be restricted in the future. Other safety regulations may be made more stringent and penalties could be increased. Such legislative and regulatory changes could have a material effect on ETP's and Regency's operations and costs of transportation service.
In addition to existing pipeline safety regulations, on January 3, 2012, President Obama signed into law the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, that increases pipeline safety regulation. Among other things, the legislation doubles the maximum administrative fines for safety violations from $100,000 to $200,000 for a single violation and from $1 million to $2 million for a related series of violations, and provides that these maximum penalty caps do not apply to civil enforcement actions; permits the DOT Secretary to mandate automatic or remote controlled shut off valves on new or entirely replaced pipelines; requires the DOT Secretary to evaluate whether integrity management system requirements should be expanded

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beyond high-consequence areas (“HCAs”), within 18 months of enactment; and provides for regulation of carbon dioxide transported by pipeline in a gaseous state and requires the DOT Secretary to prescribe minimum safety regulations for such transportation.
Environmental Matters
The operation of pipelines, plants and other facilities for gathering, compressing, treating, processing, or transporting natural gas, NGLs and other products is subject to stringent and complex federal, state, and local environmental and safety laws and regulations governing the discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations can impair ETP’s and Regency’s business activities that affect the environment in many ways, such as:
restricting how ETP and Regency can release materials or waste products into the air, water, or soils;
limiting or prohibiting construction activities in sensitive areas such as wetlands or areas of endangered species habitat, or otherwise constraining how or when construction is conducted;
requiring remedial action to mitigate pollution from former operations, or requiring plans and activities to prevent pollution from ongoing operations; and
imposing substantial liabilities on ETP and Regency for pollution resulting from its operations, including, for example, potentially enjoining the operations of facilities if it were determined that they did not comply with permit terms.
Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits. ETP and Regency have implemented environmental programs and policies designed to reduce potential liability and costs under applicable environmental laws and regulations.
The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Changes in environmental laws and regulations that result in more stringent waste handling, storage, transport, disposal, or remediation requirements will increase ETP’s and Regency’s costs for performing those activities, and if those increases are sufficiently large, they could have a material adverse effect on its operations and financial position. Moreover, risks of process upsets, accidental releases or spills are associated with ETP’s and Regency’s operations, and ETP and Regency cannot guarantee that they will they not incur significant costs and liabilities if such upsets, releases, or spills were to occur. In the event of future increases in costs, ETP and Regency may be unable to pass on those increases to their customers. While ETP and Regency believe they are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements will not have a material adverse effect on ETP or Regency, there is no assurance that this trend will continue in the future.
The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA” or “Superfund,”) 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. One class of “responsible persons” is the current owners or operators of contaminated property, even if the contamination arose as a result of historical operations conducted by previous, unaffiliated occupants of the property. Under CERCLA, “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. It also 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 into the environment. Although “petroleum” is excluded from the definition of hazardous substance under CERCLA, ETP will generate materials in the course of its operations that may be regulated as hazardous substances under CERCLA. ETP and Regency also may incur liability under the Resource Conservation and Recovery Act (“RCRA”) which imposes requirements related to the management and disposal of solid and hazardous wastes. While there exists an exclusion from the definition of hazardous wastes for “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy,” in the course of ETP’s and Regency’s operations, ETP and Regency may generate certain types of non-excluded petroleum product wastes as well as ordinary industrial wastes such as paint wastes, waste solvents, and waste compressor oils that may be regulated as hazardous or solid wastes.
ETP and Regency currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the measurement, gathering, field compression and processing of natural gas and NGLs. Although ETP and Regency used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by ETP or Regency, or on or under other locations where such wastes were taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under ETP’s or Regency’s control. These properties and

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the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, ETP and Regency could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination. A predecessor company acquired by ETP in July 2001 had previously received and responded to a request for information from the United States Environmental Protection Agency (the “EPA”) regarding its potential contribution to widespread groundwater contamination in San Bernardino, California, known as the Newmark Groundwater Contamination Superfund site. ETP has not received any follow-up correspondence from the EPA on the matter since its acquisition of the predecessor company in 2001. In addition, through ETP’s acquisitions of ongoing businesses, ETP is currently involved in several remediation projects that have cleanup costs and related liabilities. As of December 31, 2011 and 2010, accruals of $13.7 million and $13.8 million, respectively, and were recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities to cover estimated material environmental liabilities including certain matters assumed in connection with ETP’s acquisition of the HPL System, the Transwestern acquisition, potential environmental liabilities for three sites that were formerly owned by Titan Energy Partners, L.P. (“Titan”) or its predecessors and the predecessor owner’s share of certain environmental liabilities of ETC OLP.
Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the cleanup activities include remediation of several compressor sites on the Transwestern system for contamination by polychlorinated biphenyls (“PCBs”) and the costs of this work are not eligible for recovery in rates. The total accrued future estimated cost of remediation activities expected to continue through 2025 is approximately $5.7 million, which is included in the total environmental accruals mentioned above. Transwestern received approval from the FERC for the continuation of rate recovery of projected soil and groundwater remediation costs not related to PCBs for the term of its rate case settlement.
Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing potential PCB contamination. Future costs cannot be reasonably estimated because remediation activities are undertaken as potential claims are made by customers and former customers. However, such future costs are not expected to have a material impact on ETP’s financial position, results of operations or cash flows.
The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state and federal waters. The discharge of pollutants into regulated waters is prohibited, except in accord with the terms of a permit issued by EPA or the state. Any unpermitted release of pollutants, including NGLs or condensates, from our systems or facilities into regulated waters could result in fines or penalties, as well as significant remedial obligations. ETP and Regency believe that they are in substantial compliance with the Clean Water Act. The regulations were recently modified for the EPA’s Spill Prevention, Control and Countermeasures (“SPCC”) program. ETP and Regency are currently reviewing the impact to our operations and expect to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but we believe such costs will not have a material adverse effect on our financial position, results of operations or cash flows.
The Federal Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including processing plants and compressor stations. These laws and any implementing regulations may require us to obtain preapproval for the construction or modification of certain projects or facilities expected to produce air emissions, impose stringent air permit requirements or utilize specific equipment or technologies to control emissions. Failure to comply with these laws and regulations could expose us to civil and criminal enforcement actions. We have established agency-approved baseline monitoring of NOx emissions from our Katy Compressor Station in Harris County, Texas, which is in a non-attainment area for ozone. The NOx baseline has been established and we have a sufficient amount of NOx emission allowances that would allow the facility to continue at its current level of operation in the non-attainment area. On March 30, 2010, the Texas Commission on Environmental Quality (“TCEQ”) adopted two revisions to the state implementation plan responding to the EPA’s re-designation of the Houston area to a severe ozone non-attainment area. These revisions will require reductions in current emissions. By March 2013, TCEQ is required to develop a plan to address the recent change in the ozone standard from 0.08 parts per million (“ppm”) to 0.075 ppm. We expect these efforts will result in the adoption of new regulations that may require additional NOx emissions reductions at large emission sources in the Houston-Galveston ozone non-attainment area.

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In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” 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 greenhouse gases under existing provisions of the federal Clean Air Act. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA’s rules relating to emissions of greenhouse gases 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 the EPA from implementing, or requiring state environmental agencies to implement, the rules.
In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas 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 greenhouse gas emission reduction goal.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us 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, natural gas or NGLs. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations.
In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas sources in the United States on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010. On November 8, 2010, the EPA adopted an expansion of its greenhouse gas reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. Under the new rule reporting of greenhouse gas emissions from such facilities, including many of our facilities, is now required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011.
Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities from powerful winds or rising waters, or increased costs for insurance. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our propane and natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience substantially colder temperatures than their historical averages. As a result, it is difficult to predict how the market for our fuels would be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.
ETP’s pipeline operations are subject to regulation by the DOT under the Pipeline Hazardous Materials Safety Administration (“PHMSA”), pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. ETP expects that it will incur pipeline integrity costs of $3.4 million in capital costs and $17.9 million in operating and maintenance costs over the next year. Regency estimates that it will incur pipeline integrity costs of $0.8 million over the next year. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause ETP to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines.
ETP and Regency are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in ETP’s and Regency’s operations and that this information be provided to employees, state and local government authorities and citizens. ETP and Regency believe that their operations are in compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

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National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted as the industry standard in all of the states in which we operate. In some states, these laws are administered by state agencies, and in others, they are administered on a municipal level. With respect to the transportation of propane by truck, we are subject to regulations governing the transportation of hazardous materials under the Federal Motor Carrier Safety Act, administered by the U.S. Department of Transportation (“DOT”). We conduct ongoing training programs to help ensure that our operations are in compliance with applicable regulations. We believe that the procedures currently in effect at all of our facilities for the handling, storage and distribution of propane are consistent with industry standards and are in substantial compliance with applicable laws and regulations.
Employees
As of January 31, 2012, ETE and its consolidated subsidiaries employed an aggregate of 2,477 employees, none of which are represented by labor unions. We and our subsidiaries believe that our relations with our employees are satisfactory. ETP's retail propane operations were contributed to AmeriGas on January 12, 2012; therefore, our employee headcount as of January 31, 2012 excluded employees of the retail propane operations.
SEC Reporting
We file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any related amendments and supplements thereto with the Securities and Exchange Commission (“SEC”). From time to time, we may also file registration and related statements pertaining to equity or debt offerings. You may read and copy any materials we file or furnish with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-732-0330. In addition, the SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.
We provide electronic access, free of charge, to our periodic and current reports on our internet website located at http://www.energytransfer.com. These reports are available on our website as soon as reasonably practicable after we electronically file such materials with the SEC. Information contained on our website is not part of this report.

ITEM 1A.  RISK FACTORS
In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are specific to our structure as a limited partnership, our industry and our company could materially impact our future performance and results of operations. We have provided below a list of these risk factors that should be reviewed when considering an investment in our securities. These are not all the risks we face and other factors currently considered immaterial or unknown to us may impact our future operations.
Risks Inherent in an Investment in Us
Our only significant assets are our partnership interests, including the incentive distribution rights, in ETP and Regency and, therefore, our cash flow is dependent upon the ability of ETP and Regency to make distributions in respect of those partnership interests.
We do not have any significant assets other than our partnership interests in ETP and Regency. As a result, our cash flow depends on the performance of ETP, Regency and their respective subsidiaries and ETP’s and Regency’s ability to make cash distributions to us, which is dependent on the results of operations, cash flows and financial condition of ETP and Regency.
The amount of cash that ETP and Regency can distribute to their partners, including us, each quarter depends upon the amount of cash they generate from their operations, which will fluctuate from quarter to quarter and will depend on, among other things:
the amount of natural gas transported through ETP’s and Regency’s transportation pipelines and gathering systems;
the level of throughput in its processing and treating operations;
the fees they charged and the margins realized by ETP and Regency for their gathering, treating, processing, storage and transportation services;
the price of natural gas and NGLs;
the relationship between natural gas and NGL prices;
the amount of cash distributions ETP receives with respect to its ownership of AmeriGas common units;

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the weather in their respective operating areas;
the level of competition from other midstream companies, interstate pipeline companies and other energy providers;
the level of their respective operating costs;
prevailing economic conditions; and
the level of their respective derivative activities.
In addition, the actual amount of cash that ETP and Regency will have available for distribution will also depend on other factors, such as:
the level of capital expenditures they make;
the level of costs related to litigation and regulatory compliance matters;
the cost of acquisitions, if any;
the levels of any margin calls that result from changes in commodity prices;
debt service requirements;
fluctuations in working capital needs;
their ability to borrow under their respective credit facilities;
their ability to access capital markets;
restrictions on distributions contained in their respective debt agreements; and
the amount, if any, of cash reserves established by the board of directors and their respective general partners in their discretion for the proper conduct of their respective businesses.
ETE does not have any control over many of these factors, including the level of cash reserves established by the board of directors and ETP’s and Regency’s respective General Partners. Accordingly, we cannot guarantee that ETP or Regency will have sufficient available cash to pay a specific level of cash distributions to its partners.
Furthermore, Unitholders should be aware that the amount of cash that ETP and Regency have available for distribution depends primarily upon cash flow and is not solely a function of profitability, which is affected by non-cash items. As a result, ETP and Regency may declare and/or pay cash distributions during periods when they record net losses. Please read “Risks Related to the Businesses of Energy Transfer Partners and Regency Energy Partners” included in this Item 1A for a discussion of further risks affecting ETP’s and Regency’s ability to generate distributable cash flow.
We may not have sufficient cash to pay distributions at our current quarterly distribution level or to increase distributions.
The source of our earnings and cash flow is cash distributions from ETP and Regency. Therefore, the amount of distributions we are currently able to make to our Unitholders may fluctuate based on the level of distributions ETP and Regency makes to their partners. ETP or Regency may not be able to continue to make quarterly distributions at their current level or increase their quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our Unitholders if ETP or Regency increases or decreases distributions to us, the timing and amount of such increased or decreased distributions, if any, will not necessarily be comparable to the timing and amount of the increase or decrease in distributions made by ETP or Regency to us.
Our ability to distribute cash received from ETP and Regency to our Unitholders is limited by a number of factors, including:
interest expense and principal payments on our indebtedness;
restrictions on distributions contained in any current or future debt agreements;
our general and administrative expenses;
expenses of our subsidiaries other than ETP or Regency, including tax liabilities of our corporate subsidiaries, if any;
capital contributions we may make to maintain our General Partner interests in ETP or Regency upon the issuance of additional partnership securities by ETP or Regency, as applicable; and
reserves our General Partner believes prudent for us to maintain for the proper conduct of our business or to provide for future distributions.

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We cannot guarantee that in the future we will be able to pay distributions or that any distributions we do make will be at or above our current quarterly distribution. The actual amount of cash that is available for distribution to our Unitholders will depend on numerous factors, many of which are beyond our control or the control of our General Partner.
The General Partner is not elected by the Unitholders and cannot be removed without its consent.
Unlike the holders of common stock in a corporation, our Unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our Unitholders do not have the ability to elect our General Partner or the officers or directors of our General Partner.
Furthermore, if our Unitholders are dissatisfied with the performance of our General Partner, they have little ability to remove our General Partner. Our General Partner may not be removed except upon the vote of the holders of at least 66  2/3% of our outstanding units. Our directors and executive officers directly or indirectly own 69,841,213 Common Units, representing approximately 31% of our outstanding Common Units, it will be particularly difficult for our General Partner to be removed without the consent of our directors and executive officers. As a result, the price at which our Common Units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.
A reduction in ETP’s or Regency’s distributions will disproportionately affect the amount of cash distributions to which we are entitled.
Our indirect ownership of 100% of the incentive distribution rights in ETP, through our ownership of equity interests in ETP GP, the holder of the incentive distribution rights, entitles us to receive our pro rata share of specified percentages of total cash distributions made by ETP as it reaches established target cash distribution levels. We currently receive our pro rata share of cash distributions from ETP based on the highest incremental percentage, 48%, to which ETP GP is entitled pursuant to its incentive distribution rights in ETP. A decrease in the amount of distributions by ETP to less than $0.4125 per Common Unit per quarter would reduce ETP GP’s percentage of the incremental cash distributions above $0.3175 per Common Unit per quarter from 48% to 23%. As a result, any such reduction in quarterly cash distributions from ETP would have the effect of disproportionately reducing the amount of all distributions that we receive from ETP based on our ownership interest in the incentive distribution rights in ETP as compared to cash distributions we receive from ETP on our General Partner interest in ETP and our ETP Common Units.
Similarly, we receive a pro rata share of incremental cash distributions from Regency at the 23% level pursuant to Regency GP's incentive distribution rights in Regency. A decrease in the amount of distributions by Regency to less than $0.4375 per Common Unit per quarter would have reduced Regency GP’s percentage of the incremental cash distributions above $0.4025 per Common Unit per quarter from 23% to 13%. As a result, any such reduction in quarterly cash distributions from Regency would have the effect of disproportionately reducing the amount of all distributions that we receive from Regency based on our ownership interest in the incentive distribution rights of Regency as compared to cash distributions we receive from Regency on our General Partner interest in Regency and our Regency Common Units.
The consolidated debt level and debt agreements of ETP and Regency and those of their subsidiaries may limit the distributions we receive from ETP and Regency, as well as our future financial and operating flexibility.
As of December 31, 2011, ETP had approximately $7.81 billion of consolidated debt outstanding and Regency had approximately $1.69 billion of consolidated debt outstanding, excluding the credit facilities of their joint ventures. ETP’s and Regency’s levels of indebtedness affect their operations in several ways, including, among other things:
a significant portion of ETP’s and Regency’s cash flows from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions to us;
covenants contained in ETP’s and Regency’s existing debt agreements require ETP and Regency to meet financial tests that may adversely affect their flexibility in planning for and reacting to changes in their respective businesses;
ETP’s and Regency’s ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership purposes may be limited;
ETP and Regency may be at a competitive disadvantage relative to similar companies that have less debt;
ETP and Regency may be more vulnerable to adverse economic and industry conditions as a result of their significant debt levels; and
failure to comply with the various restrictive covenants of the debt agreements could negatively impact ETP’s and Regency’s ability to incur additional debt, including their ability to utilize the available capacity under their revolving credit facilities, and to pay distributions.

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We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.
Our ability to make scheduled payments on or to refinance our debt obligations depends on our financial and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We cannot assure Unitholders that we will maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets or operations, seek additional capital or restructure or refinance our indebtedness. We cannot assure Unitholders that we would be able to take any of these actions, that these actions would be successful and permit us to meet our scheduled debt service obligations or that these actions would be permitted under the terms of our existing or future debt agreements. In the absence of such cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our credit facilities restrict our ability to dispose of assets and use the proceeds from the disposition. We may not be able to consummate those dispositions or to obtain the proceeds that we could realize from them, and any proceeds may not be adequate to meet any debt service obligations then due.
ETP and Regency are not prohibited from competing with us.
Neither our partnership agreement nor the partnership agreements of ETP or Regency prohibit ETP or Regency from owning assets or engaging in businesses that compete directly or indirectly with us. Additionally, ETP’s partnership agreement prohibits us from engaging in the retail propane business in the United States. In addition, ETP and/or Regency may acquire, construct or dispose of any assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets.
Construction of new expansion projects will require significant amounts of debt and equity financing which may not be available to ETP or Regency on acceptable terms, or at all.
ETP and Regency plan to fund their growth capital expenditures, including any new future pipeline construction projects ETP or Regency may undertake, with proceeds from sales of ETP’s or Regency’s debt and equity securities and borrowings under their respective revolving credit facilities; however, ETP or Regency cannot be certain that they will be able to issue debt and equity securities on terms satisfactory to them, or at all. In addition, ETP or Regency may be unable to obtain adequate funding under their current revolving credit facility because ETP’s or Regency’s lending counterparties may be unwilling or unable to meet their funding obligations. If ETP or Regency are unable to finance their expansion projects as expected, ETP or Regency could be required to seek alternative financing, the terms of which may not be attractive to ETP or Regency, or to revise or cancel its expansion plans.
A significant increase in ETP’s or Regency’s indebtedness that is proportionately greater than ETP’s or Regency’s respective issuances of equity could negatively impact ETP’s or Regency’s respective credit ratings or their ability to remain in compliance with the financial covenants under their respective revolving credit agreements, which could have a material adverse effect on ETP’s or Regency’s financial condition, results of operations and cash flows.
Increases in interest rates could materially adversely affect our business, results of operations, cash flows and financial condition.
In addition to our exposure to commodity prices, we have significant exposure to changes in interest rates. As of December 31, 2011, we had approximately $717.9 million of consolidated variable rate debt outstanding, which consisted of borrowings under our revolving credit facility of $71.5 million and borrowings under ETP’s and Regency’s revolving credit facilities of $314.4 million and $332.0 million, respectively and excludes borrowings of ETP’s and Regency’s joint ventures. To the extent that we have debt with floating interest rates, our results of operations, cash flows and financial condition could be materially adversely affected by increases in interest rates. We manage a portion of our interest rate exposures by utilizing interest rate swaps.
As of December 31, 2011, ETP had a total of $1.15 billion of notional amount of forward-starting interest rate swaps outstanding to hedge the anticipated issuance of senior notes in 2012 and 2013. In addition, ETP had a total of $500 million of notional amount of interest rate swaps that swap a portion of our fixed rate debt to floating. Regency also had $250 million of notional amount of interest rate swaps that swap a portion of its floating rate debt to a fixed rate.
An increase in interest rates may also cause a corresponding decline in demand for equity investments, in general, and in particular for yield-based equity investments such as our Common Units. Any such reduction in demand for our Common Units resulting from other more attractive investment opportunities may cause the trading price of our Common Units to decline.

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The credit and risk profile of our General Partner and its owners could adversely affect our credit ratings and profile.
The credit and business risk profiles of our General Partner or indirect owners of our General Partner may be factors in credit evaluations of us as a publicly traded limited partnership due to the significant influence of our General Partner and indirect owners over our business activities, including our cash distributions, acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of our General Partner and its owners, including the degree of their financial leverage and their dependence on cash flow from us to service their indebtedness.
We may issue an unlimited number of limited partner interests without the consent of our Unitholders, which will dilute Unitholders’ ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.
Our partnership agreement allows us to issue an unlimited number of additional limited partner interests, including securities senior to the Common Units, without the approval of our Unitholders. The issuance of additional Common Units or other equity securities by us will have the following effects:
our Unitholders’ current proportionate ownership interest in us will decrease;
the amount of cash available for distribution on each Common Unit or partnership security may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding Common Unit may be diminished; and
the market price of our Common Units may decline.
In addition, ETP and Regency may sell an unlimited number of limited partner interests without the consent of the respective Unitholders, which will dilute existing interests of the respective Unitholders, including us. The issuance of additional Common Units or other equity securities by ETP will have essentially the same effects as detailed above.
The market price of our Common Units could be adversely affected by sales of substantial amounts of our units in the public markets, including sales by our existing Unitholders.
Sales by any of our existing Unitholders of a substantial number of our units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our units or could impair our ability to obtain capital through an offering of equity securities. We do not know whether any such sales would be made in the public market or in private placements, nor do we know what impact such potential or actual sales would have on our unit price in the future.
Control of our General Partner may be transferred to a third party without Unitholder consent.
Our General Partner may transfer its general partner interest in us to a third party without the consent of our Unitholders. Furthermore, the members of our General Partner may transfer all or part of their ownership interest in our General Partner to a third party without the consent of the Unitholders. The new owner or owners of our General Partner or the general partner of the General Partner would then be in a position to replace the directors and officers of our General Partner and control the decisions made and actions taken by the board of directors and officers.
Our General Partner has only one executive officer, and we are dependent on third parties, including key personnel of ETP under a shared services agreement, to provide the financial, accounting, administrative and legal services necessary to operate our business.
John W. McReynolds, the President and Chief Financial Officer of our General Partner, is the only executive officer charged with managing our business other than through our shared services agreement with ETP. We do not currently have a plan for identifying a successor to Mr. McReynolds in the event that he retires, dies or becomes disabled. If Mr. McReynolds ceases to serve as the President and Chief Financial Officer of our General Partner for any reason, we would be without executive management other than through our shared services agreement with ETP until one or more new executive officers are selected by the board of directors of our General Partner. As a consequence, the loss of Mr. McReynolds’ services could have a material negative impact on the management of our business.
Moreover, we rely on the services of key personnel of ETP, including the ongoing involvement and continued leadership of Kelcy L. Warren, one of the founders of ETP’s midstream business, as well as other key members of ETP’s management team such as Marshall S. (Mackie) McCrea, III, President and Chief Operating Officer. Mr. Warren has been integral to the success of ETP’s midstream and intrastate transportation and storage businesses because of his ability to identify and develop strategic business opportunities. Losing his leadership could make it difficult for ETP to identify internal growth projects and accretive acquisitions, which could have a material adverse effect on ETP’s ability to increase the cash distributions paid on its partnership interests.

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ETP’s executive officers that provide services to us pursuant to a shared services agreement allocate their time between us and ETP. To the extent that these officers face conflicts regarding the allocation of their time, we may not receive the level of attention from them that the management of our business requires. If ETP is unable to provide us with a sufficient number of personnel with the appropriate level of technical accounting and financial expertise, our internal accounting controls could be adversely impacted.
An increase in interest rates may cause the market price of our units to decline.
Like all equity investments, an investment in our units 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 such as publicly traded limited partnership interests. Reduced demand for our units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our units to decline.
Limited partner’s liability may not be limited, and our Unitholders may have to repay distributions or make additional contributions to us under limited circumstances.
As a limited partner in a partnership organized under Delaware law, a limited partner could be held liable for our obligations to the same extent as a general partner if it participates in the “control” of our business. Our general partner generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to our General Partner. Additionally, the limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in many jurisdictions in which we do business. In some of the jurisdictions in which we do business, the applicable statutes do not define control, but do permit limited partners to engage in certain activities, including, among other actions, taking any action with respect to the dissolution of the partnership, the sale, exchange, lease or mortgage of any asset of the partnership, the admission or removal of the general partner and the amendment of the partnership agreement. A limited partner could, however, be liable for any and all of our obligations as if it was a general partner if:
a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or
a limited partner’s right to act with other Unitholders to take other actions under our partnership agreement is found to constitute “control” of our business.
Under limited circumstances, our Unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, neither Energy Transfer Equity, ETP nor Regency may make a distribution to its Unitholders if the distribution would cause Energy Transfer Equity’s, ETP’s or Regency’s respective liabilities to exceed the fair value of their respective assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, partners who received the distribution and knew at the time of the distribution that it violated Delaware law will be liable to the partnership for the distribution amount. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
If we cease to manage and control ETP or Regency in the future, we may be deemed to be an investment company under the Investment Company Act of 1940.
If we cease to manage and control ETP or Regency and are deemed to be an investment company under the Investment Company Act of 1940 (the “Investment Company Act”) we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the Securities and Exchange Commission or modify our organizational structure or our contract 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 affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, 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 or our affiliates.

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Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes, in which case we would be treated as a corporation for federal income tax purposes. For further discussion of the importance of our treatment as a partnership for federal income tax purposes and the implications that would result from our treatment as a corporation in any taxable year, please read the risk factor below entitled “Our tax treatment depends on our continuing status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us, ETP or Regency as a corporation for federal income tax purposes or if we, ETP or Regency become subject to a material amount of additional entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to Unitholders.
If ETP GP or Regency GP withdraws or is removed as ETP’s or Regency’s General Partner, as applicable, then we would lose control over the management and affairs of ETP or Regency, the risk that we would be deemed an investment company under the Investment Company Act of 1940 would be exacerbated and our indirect ownership of the General Partner interests and 100% of the incentive distribution rights in ETP or Regency could be cashed out or converted into ETP or Regency Common Units, as applicable, at an unattractive valuation.
Under the terms of ETP’s or Regency’s respective partnership agreements, ETP GP or Regency GP, as applicable, will be deemed to have withdrawn as General Partner if, among other things, it:
voluntarily withdraws from the partnership by giving notice to the other partners;
transfers all, but not less than all, of its partnership interests to another entity in accordance with the terms of ETP’s or Regency’s partnership agreement, as applicable;
makes a general assignment for the benefit of creditors, files a voluntary bankruptcy petition, seeks to liquidate, acquiesces in the appointment of a trustee, receiver or liquidator, or becomes subject to an involuntary bankruptcy petition; or
dissolves itself under Delaware law without reinstatement within the requisite period.
In addition, ETP GP and Regency GP can be removed as ETP’s or Regency's General Partner if that removal is approved by Unitholders holding at least 66 2/3% of ETP’s or Regency’s respective outstanding Common Units (including units held by ETP GP or Regency GP and their respective affiliates). Currently, ETP GP and its affiliates own approximately 22% of ETP’s outstanding Common Units, and Regency GP and its affiliates own approximately 17% of Regency’s outstanding Common Units.
If ETP GP or Regency GP withdraws from being ETP’s or Regency’s respective General Partner in compliance with ETP’s or Regency’s partnership agreement, as applicable, or is removed from being ETP’s or Regency’s respective General Partner under circumstances not involving a final adjudication of actual fraud, gross negligence or willful and wanton misconduct, it may require the successor General Partner to purchase its General Partner interests, incentive distribution rights and limited partner interests in ETP or Regency, as applicable, for fair market value. If ETP GP or Regency GP withdraws from being ETP’s or Regency’s respective General Partner in violation of ETP’s or Regency’s partnership agreement, as applicable, or is removed from being ETP’s or Regency’s General Partner in circumstances where a court enters a judgment that cannot be appealed finding it liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as ETP’s or Regency’s General Partner, and the successor General Partner does not exercise its option to purchase the General Partner interests, incentive distribution rights and limited partner interests in ETP or Regency, as applicable, for fair market value, then the General Partner interests and incentive distribution rights in ETP or Regency, as applicable, could be converted into limited partner interests pursuant to a valuation performed by an investment banking firm or other independent expert. Under any of the foregoing scenarios, ETP GP or Regency GP would lose control over the management and affairs of ETP or Regency, as applicable, thereby increasing the risk that we would be deemed an investment company subject to regulation under the Investment Company Act of 1940. In addition, our indirect ownership of the General Partner interests and 100% of the incentive distribution rights in ETP and Regency, to which a significant portion of the value of our Common Units is currently attributable, could be cashed out or converted into ETP or Regency Common Units, as applicable, at an unattractive valuation.
Our Partnership Agreement restricts the rights of Unitholders owning 20% or more of our units.
Our Unitholders’ voting rights are restricted by the provision in our partnership agreement generally providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner and its affiliates, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our Unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our Unitholders’ ability to influence the manner or direction of our management. As a result, the price at which our Common Units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

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Future sales of the ETP or Regency Common Units we own or other limited partner interests in the public market could reduce the market price of our Unitholders’ limited partner interests.
As of December 31, 2011, we owned approximately 50.2 million Common Units of ETP and approximately 26.3 million Common Units of Regency, and SUG, as a subsidiary of ETE, is expected to receive $105 million of additional ETP Common Units upon ETP's consummation of its acquisition of Citrus Corp. (the "Citrus Acquisition"). If we were to sell and/or distribute our ETP or Regency Common Units to the holders of our equity interests in the future, those holders may dispose of some or all of these units. The sale or disposition of a substantial portion of these units in the public markets could reduce the market price of ETP’s or Regency’s outstanding Common Units and our receipt of cash distributions.
Cost reimbursements due to our General Partner may be substantial and may reduce our ability to pay the distributions to our Unitholders.
Prior to making any distributions to our Unitholders, we will reimburse our General Partner for all expenses it has incurred on our behalf. In addition, our General Partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by our General Partner. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to our Unitholders. Our General Partner has sole discretion to determine the amount of these expenses and fees.
In addition, under Delaware partnership law, our General Partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our General Partner. To the extent our General Partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our General Partner, our General Partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash available for distribution to our Unitholders and cause the value of our Common Units to decline.
An impairment of goodwill and intangible assets could reduce our earnings.
As of December 31, 2011, our consolidated balance sheets reflected $2.04 billion of goodwill and $1.07 billion of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur, indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ capital and balance sheet leverage as measured by debt to total capitalization.
ETP or Regency may issue additional Common Units, which may increase the risk that ETP or Regency will not have sufficient available cash to maintain or increase its per unit distribution level.
The partnership agreements of each ETP and Regency allow ETP and Regency, respectively, to issue an unlimited number of additional limited partner interests. The issuance of additional common units or other equity securities by ETP or Regency will have the following effects:
Unitholders’ current proportionate ownership interest in ETP or Regency, as applicable, will decrease;
the amount of cash available for distribution on each common unit or partnership security may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding common unit may be diminished; and
the market price of ETP’s or Regency’s Common Units, as applicable, may decline.
The payment of distributions on any additional units issued by ETP or Regency may increase the risk that ETP or Regency, as applicable, may not have sufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to meet our obligations.

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Risks Related to Conflicts of Interest
Although we control ETP and Regency through our ownership of their respective General Partners, ETP’s General Partner owes fiduciary duties to ETP and ETP’s Unitholders, and Regency’s General Partner owes fiduciary duties to Regency and Regency’s Unitholders, which may conflict with our interests.
Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, on the one hand, and ETP, Regency and their respective limited partners, on the other hand. The directors and officers of ETP’s and Regency’s General Partners have fiduciary duties to manage ETP and Regency, respectively, in a manner beneficial to us. At the same time, the General Partners have fiduciary duties to manage ETP and Regency, respectively, in a manner beneficial to ETP, Regency and their respective limited partners. The board of directors of ETP’s General Partner or Regency’s general partner will resolve any such conflict and have broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest.
For example, conflicts of interest with ETP or Regency may arise in the following situations:
the allocation of shared overhead expenses to ETP, Regency and us;
the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and ETP or Regency, on the other hand;
the determination of the amount of cash to be distributed to ETP’s or Regency’s partners and the amount of cash to be reserved for the future conduct of ETP’s or Regency’s business;
the determination whether to make borrowings under ETP’s or Regency’s respective revolving credit facility to pay distributions to ETP’s or Regency’s partners, as applicable; and
any decision we make in the future to engage in business activities independent of ETP or Regency.
The fiduciary duties of our General Partner’s officers and directors may conflict with those of ETP’s or Regency’s respective General Partners.
Conflicts of interest may arise because of the relationships among ETP, Regency, their General Partners and us. Our General Partner’s directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our Unitholders. Some of our General Partner’s directors are also directors and officers of ETP’s General Partner or Regency’s General Partner, and have fiduciary duties to manage the respective businesses of ETP and Regency in a manner beneficial to ETP, Regency and their respective Unitholders. The resolution of these conflicts may not always be in our best interest or that of our Unitholders.
Affiliates of our General Partner are not prohibited from competing with us.
Our partnership agreement provides that our General Partner will be restricted from engaging in any business activities other than acting as our General Partner and those activities incidental to its ownership of interests in us. Except as provided in our partnership agreement, affiliates of our General Partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us.
Potential conflicts of interest may arise among our General Partner, its affiliates and us. Our General Partner and its affiliates have limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of us.
Conflicts of interest may arise among our General Partner and its affiliates, on the one hand, and us, on the other hand. As a result of these conflicts, our General Partner may favor its own interests and the interests of its affiliates over our interests. These conflicts include, among others, the following:
Our General Partner is allowed to take into account the interests of parties other than us, including ETP, Regency and their respective affiliates and any General Partners and limited partnerships acquired in the future, in resolving conflicts of interest, which has the effect of limiting its fiduciary duties to us.
Our General Partner has limited its liability and reduced its fiduciary duties under the terms of our partnership agreement, while also restricting the remedies available for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing our units, Unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.
Our General Partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution.
Our General Partner determines which costs it and its affiliates have incurred are reimbursable by us.

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Our partnership agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us.
Our General Partner controls the enforcement of obligations owed to us by it and its affiliates.
Our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.
Our partnership agreement limits our General Partner’s fiduciary duties to us and restricts the remedies available for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the standards to which our General Partner would otherwise be held by state fiduciary duty law. For example, our Partnership Agreement:
permits our General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our General Partner. This entitles our General Partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;
provides that our General Partner is entitled to make other decisions in “good faith” if it reasonably believes that the decisions are in our best interests;
generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the Audit and Conflicts Committee of the board of directors of our General Partner and not involving a vote of Unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our General Partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
provides that our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.
Our General Partner has a limited call right that may require Unitholders to sell their units at an undesirable time or price.
If at any time our General Partner and its affiliates own more than 90% of our outstanding units, our General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, Unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. As of December 31, 2011, the directors and executive officers of our General Partner owned approximately 31% of our Common Units.
ETP and Regency own interstate pipelines that are subject to rate regulation by the Federal Energy Regulatory Commission and, in the event that 15% or more of our outstanding Common Units, in the aggregate, are held by persons who are not eligible holders, Common Units held by persons who are not eligible holders will be subject to the possibility of redemption at the then-current market price.
ETP and Regency own interstate pipelines that are subject to rate regulation of the Federal Energy Regulatory Commission, FERC, and as a result our General Partner has the right under our partnership agreement to institute procedures, by giving notice to each of our Unitholders, that would require transferees of Common Units and, upon the request of our General Partner, existing holders of our Common Units to certify that they are Eligible Holders. The purpose of these certification procedures would be to enable us to utilize a federal income tax expense as a component of the pipeline’s rate base upon which tariffs may be established under FERC rate-making policies applicable to entities that pass-through their taxable income to their owners. Eligible Holders are individuals or entities subject to United States federal income taxation on the income generated by us or entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. If these tax certification procedures are implemented and 15% or more of our outstanding Common Units are held by persons who are not Eligible Holders, we will have the right to redeem the units held by persons who are not Eligible Holders at the then-current market price. The redemption price would be paid in cash or by delivery of a promissory note, as determined by our General Partner.

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Risks Related to the Businesses of ETP and Regency
Since our cash flows consist exclusively of distributions from ETP and Regency, risks to the businesses of ETP and Regency are also risks to us. We have set forth below risks to the businesses of ETP and Regency, the occurrence of which could have a negative impact on their respective financial performance and decrease the amount of cash they are able to distribute to us.
ETP and Regency are exposed to the credit risk of their respective customers, and an increase in the nonpayment and nonperformance by their respective customers could reduce their respective ability to make distributions to their Unitholders, including to us.
The risks of nonpayment and nonperformance by ETP’s and Regency’s respective customers are a major concern in their respective businesses. Participants in the energy industry have been subjected to heightened scrutiny from the financial markets in light of past collapses and failures of other energy companies. ETP and Regency are subject to risks of loss resulting from nonpayment or nonperformance by their respective customers. The current tightening of credit in the financial markets may make it more difficult for customers to obtain financing and, depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by ETP’s and Regency’s customers. Any substantial increase in the nonpayment and nonperformance by ETP’s or Regency’s customers could have a material adverse effect on ETP’s or Regency’s respective results of operations and operating cash flows.
The profitability of certain activities in midstream and intrastate transportation and storage operations are largely dependent upon natural gas commodity prices, price spreads between two or more physical locations and market demand for natural gas and NGLs, which are factors beyond ETP’s or Regency’s control and have been volatile.
Income from midstream and intrastate transportation and storage operations is exposed to risks due to fluctuations in commodity prices. In the past, the prices of natural gas and NGLs have been extremely volatile, and ETP and Regency expect this volatility to continue. For example, during the year ended December 31, 2011, the NYMEX settlement price for the prompt month contract ranged from a high of $4.38 per MMBtu to a low of $3.36 per MMBtu. Additionally, a composite of the Mt. Belvieu average NGLs price based upon ETP’s average NGLs composition during the year ended December 31, 2011 ranged from a high of approximately $1.36 per gallon to a low of approximately $1.15 per gallon.
The markets and prices for natural gas and NGLs depend upon factors beyond ETP’s and Regency’s control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions, and other factors, including:
the impact of weather on the demand for oil and natural gas;
the level of domestic oil and natural gas production;
the availability of imported oil and natural gas;
actions taken by foreign oil and gas producing nations;
the availability of local, intrastate and interstate transportation systems;
the price, availability and marketing of competitive fuels;
the demand for electricity;
the impact of energy conservation efforts; and
the extent of governmental regulation and taxation.
The use of derivative financial instruments could result in material financial losses by ETP and Regency.
From time to time, ETP and Regency have sought to limit a portion of the adverse effects resulting from changes in natural gas and other commodity prices and interest rates by using derivative financial instruments and other risk management mechanisms and by their trading, marketing and/or system optimization activities. To the extent that either ETP or Regency hedges its commodity price and interest rate exposures, it foregoes the benefits it would otherwise experience if commodity prices or interest rates were to change favorably. In addition, even though monitored by management, ETP’s and Regency’s derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to ETP’s or Regency’s physical or financial positions, or internal hedging policies and procedures are not followed.

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ETP’s and Regency’s success depends upon their ability to continually contract for new sources of natural gas supply and natural gas transportation services.
In order to maintain or increase throughput levels on ETP’s and Regency’s gathering and transportation pipeline systems and asset utilization rates at their treating and processing plants, ETP and Regency must continually contract for new natural gas supplies and natural gas transportation services. ETP and Regency may not be able to obtain additional contracts for natural gas supplies for their natural gas gathering systems, and they may be unable to maintain or increase the levels of natural gas throughput on their transportation pipelines. The primary factors affecting ETP’s and Regency’s ability to connect new supplies of natural gas to their gathering systems include its success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity and production of natural gas near ETP’s and Regency’s gathering systems or in areas that provide access to its transportation pipelines or markets to which their systems connect. The primary factors affecting ETP’s and Regency’s ability to attract customers to their transportation pipelines consist of their access to other natural gas pipelines, natural gas markets, natural gasfired power plants and other industrial end-users and the level of drilling and production of natural gas in areas connected to these pipelines and systems.
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 activity and production generally decrease as oil and natural gas prices decrease. ETP and Regency have no control over the level of drilling activity in their areas of operation, the amount of reserves underlying the wells and the rate at which production from a well will decline, sometimes referred to as the “decline rate.” In addition, ETP and Regency have no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital.
A substantial portion of ETP’s and Regency’s assets, including their gathering systems and their processing and treating plants, are connected to natural gas reserves and wells for which the production will naturally decline over time. Accordingly, ETP’s and Regency’s cash flows will also decline unless they are able to access new supplies of natural gas by connecting additional production to these systems.
ETP’s and Regency’s transportation pipelines are also dependent upon natural gas production in areas served by their pipelines or in areas served by other gathering systems or transportation pipelines that connect with their transportation pipelines. A material decrease in natural gas production in ETP’s and Regency’s areas of operation or in other areas that are connected to ETP’s or Regency’s areas of operation by third party gathering systems or pipelines, as a result of depressed commodity prices or otherwise, would result in a decline in the volume of natural gas ETP and Regency handle, which would reduce their respective revenues and operating income. In addition, ETP’s and Regency’s future growth will depend, in part, upon whether they can contract for additional supplies at a greater rate than the natural decline rate in their currently connected supplies.
ETP and Regency may not be able to fully execute their growth strategies if they encounter increased competition for qualified assets.
ETP and Regency each have strategies that contemplate growth through the development and acquisition of a wide range of midstream and other energy infrastructure assets while maintaining strong balance sheets. These strategies include constructing and acquiring additional assets and businesses to enhance their ability to compete effectively and diversify their respective asset portfolios, thereby providing more stable cash flow. ETP and Regency regularly consider and enter into discussions regarding, and are currently contemplating, the acquisition of additional assets and businesses, stand alone development projects or other transactions that ETP and Regency believe will present opportunities to realize synergies and increase cash flow.
Consistent with their acquisition strategies, managements of ETP and Regency is continuously engaged in discussions with potential sellers regarding the possible acquisition of additional assets or businesses. Such acquisition efforts may involve ETP or Regency management’s participation in processes that involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which ETP or Regency believes it is the only party or one of a very limited number of potential buyers in negotiations with the potential seller. We cannot assure that ETP’s or Regency’s current or future acquisition efforts will be successful or that any such acquisition will be completed on favorable terms.
In addition, ETP and Regency each are experiencing increased competition for the assets they purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in ETP or Regency losing to other bidders more often or acquiring assets at higher prices, both of which would limit ETP’s or Regency’s ability to fully execute their respective growth strategies. Inability to execute their respective growth strategies may materially adversely impact ETP’s or Regency’s results of operations.

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If ETP and Regency do not make acquisitions on economically acceptable terms, their future growth could be limited.
ETP’s and Regency’s results of operations and their ability to grow and to increase distributions to Unitholders will depend in part on their ability to make acquisitions that are accretive to their respective distributable cash flow.
ETP and Regency may be unable to make accretive acquisitions for any of the following reasons, among others:
inability to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
inability to raise financing for such acquisitions on economically acceptable terms; or
inability to outbid by competitors, some of which are substantially larger than ETP or Regency and may have greater financial resources and lower costs of capital.
Furthermore, even if ETP or Regency consummates acquisitions that it believes will be accretive, those acquisitions may in fact adversely affect its results of operations or result in a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including the risk that ETP or Regency may:
fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;
decrease its liquidity by using a significant portion of its available cash or borrowing capacity to finance acquisitions;
significantly increase its interest expense or financial leverage if the acquisition is financed with additional debt;
encounter difficulties operating in new geographic areas or new lines of business;
incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which there is no indemnity or the indemnity is inadequate;
be unable to hire, train or retrain qualified personnel to manage and operate its growing business and assets;
less effectively manage its historical assets, due to the diversion of management’s attention from other business concerns; or
incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.
If ETP and Regency consummate future acquisitions, their respective capitalization and results of operations may change significantly. As ETP and Regency determine the application of their funds and other resources, Unitholders will not have an opportunity to evaluate the economics, financial and other relevant information that ETP and Regency will consider.
If ETP and Regency do not continue to construct new pipelines, their future growth could be limited.
During the past several years, ETP and Regency have constructed several new pipelines, and ETP and Regency are currently involved in constructing additional pipelines. ETP’s and Regency’s results of operations and their ability to grow and to increase distributable cash flow per unit will depend, in part, on their ability to construct pipelines that are accretive to their respective distributable cash flow. ETP or Regency may be unable to construct pipelines that are accretive to distributable cash flow for any of the following reasons, among others:
inability to identify pipeline construction opportunities with favorable projected financial returns;
inability to raise financing for its identified pipeline construction opportunities; or
inability to secure sufficient natural gas transportation commitments from potential customers due to competition from other pipeline construction projects or for other reasons.
Furthermore, even if ETP or Regency constructs a pipeline that it believes will be accretive, the pipeline may in fact adversely affect its results of operations or fail to achieve results projected prior to commencement of construction.
Expanding ETP’s and Regency’s business by constructing new pipelines and treating and processing facilities subjects ETP and Regency to risks.
One of the ways that ETP and Regency have grown their respective businesses is through the construction of additions to existing gathering, compression, treating, processing and transportation systems. The construction of a new pipeline or the expansion of an existing pipeline, by adding additional compression capabilities or by adding a second pipeline along an existing pipeline, and the construction of new processing or treating facilities, involve numerous regulatory, environmental, political and legal uncertainties beyond ETP’s and Regency’s control and require the expenditure of significant amounts of capital to be financed through borrowings, the issuance of additional equity or from operating cash flow. If ETP or Regency undertakes these projects,

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they may not be completed on schedule or at all or at the budgeted cost. A variety of factors outside ETP’s or Regency’s control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as the performance by third-party contractors may result in increased costs or delays in construction. Cost overruns or delays in completing a project could have a material adverse effect on ETP’s or Regency’s results of operations and cash flows. Moreover, revenues may not increase immediately following the completion of a particular project. For instance, if ETP or Regency builds a new pipeline, the construction will occur over an extended period of time, but ETP or Regency, as applicable, may not materially increase its revenues until long after the project’s completion. In addition, the success of a pipeline construction project will likely depend upon the level of natural gas exploration and development drilling activity and the demand for pipeline transportation in the areas proposed to be serviced by the project as well as ETP’s and Regency’s abilities to obtain commitments from producers in these areas to utilize the newly constructed pipelines. In this regard, ETP and Regency may construct facilities to capture anticipated future growth in natural gas production in a region in which such growth does not materialize. As a result, new facilities may be unable to attract enough throughput or contracted capacity reservation commitments to achieve ETP’s or Regency’s expected investment return, which could adversely affect its results of operations and financial condition.
ETP and Regency depend on certain key producers for a significant portion of their supplies of natural gas. The loss of, or reduction in, any of these key producers could adversely affect ETP’s or Regency’s respective business and operating results.
ETP and Regency rely on a limited number of producers for a significant portion of their natural gas supplies. These contracts have terms that range from month-to-month to life of lease. As these contracts expire, ETP and Regency will have to negotiate extensions or renewals or replace the contracts with those of other suppliers. ETP and Regency may be unable to obtain new or renewed contracts on favorable terms, if at all. The loss of all or even a portion of the volumes of natural gas supplied by these producers and other customers, as a result of competition or otherwise, could have a material adverse effect on ETP’s and Regency’s business, results of operations, and financial condition.
ETP and Regency depend on key customers to transport natural gas through their pipelines.
ETP and Regency rely on a limited number of major shippers to transport certain minimum volumes of natural gas on their respective pipelines, and Regency maintains contracts for compression services with a limited number of key customers. The failure of the major shippers on ETP’s or Regency’s pipelines or of other key customers to fulfill their contractual obligations under these contracts could have a material adverse effect on the cash flow and results of operations of us, ETP or Regency if ETP or Regency, as applicable, was not able to replace these customers under arrangements that provide similar economic benefits as these existing contracts.
Federal, state or local regulatory measures could adversely affect the business and operations of ETP’s or Regency’s midstream and intrastate assets.
Midstream and intrastate transportation and storage operations are generally exempt from FERC regulation under the NGA, but FERC regulation still significantly affects ETP’s and Regency’s businesses and the market for their products. The rates, terms and conditions of some of the transportation and storage services ETP provides on the HPL System, the East Texas pipeline, the Oasis pipeline and the ET Fuel System are subject to FERC regulation under Section 311 of the Natural Gas Policy Act (“NGPA”) similarly, FERC regulates the rates, terms and conditions of services with regard to Section 311 service provided by RIGS. Under Section 311, rates charged for transportation and storage must be fair and equitable. Amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s statement of operating conditions, are subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than its currently approved rates, ETP or Regency may suffer a loss of revenue. Failure to observe the service limitations applicable to storage and transportation service under Section 311, failure to comply with the rates approved by FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in an alteration of jurisdictional status and/or the imposition of administrative, civil and criminal penalties.
FERC has adopted market-monitoring and annual and quarterly reporting regulations, which regulations are applicable to many intrastate pipelines as well as other entities that are otherwise not subject to FERC’s NGA jurisdiction, such as natural gas marketers. These regulations are intended to increase the transparency of wholesale energy markets, to protect the integrity of such markets, and to improve FERC’s ability to assess market forces and detect market manipulation. These regulations may result in administrative burdens and additional compliance costs for ETP and Regency.
ETP and Regency hold transportation contracts with interstate pipelines that are subject to FERC regulation. As shippers on an interstate pipeline, ETP and Regency are subject to FERC requirements related to use of the interstate capacity. Any failure on ETP’s or Regency’s part to comply with the FERC’s regulations or orders could result in the imposition of administrative, civil and criminal penalties.

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ETP’s intrastate transportation and storage operations are subject to state regulation in Texas, Louisiana, Utah and Colorado, the states in which ETP conducts this type of operation. Regency’s intrastate transportation operations are subject to regulation in Louisiana, the state in which Regency conducts this type of operation. ETP’s intrastate transportation operations located in Texas are subject to regulation as common purchasers and as gas utilities by the TRRC. The TRRC’s jurisdiction extends to both rates and pipeline safety. The rates ETP charges for transportation and storage services are deemed just and reasonable under Texas law unless challenged in a complaint. Should a complaint be filed or should regulation become more active, ETP’s or Regency’s business may be adversely affected.
ETP’s and Regency’s midstream and intrastate transportation operations are also subject to ratable take and common purchaser statutes in the states in which they conduct those types of operations. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting ETP’s or Regency’s rights as an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and some of the states in which ETP and Regency operate have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which ETP and Regency operate that have adopted some form of complaint-based regulation, like Texas, generally allow natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering rates and access. Other state and local regulations also affect ETP’s or Regency’s business.
ETP’s storage facilities are also subject to the jurisdiction of the TRRC. Generally, the TRRC has jurisdiction over all underground storage of natural gas in Texas, unless the facility is part of or connected to an interstate gas pipeline system. Because the natural gas storage facilities of the ET Fuel System and HPL System are only connected to intrastate gas pipelines, they fall within the TRRC’s jurisdiction and must be operated pursuant to TRRC permit. Certain changes in ownership or operation of TRRC-jurisdictional storage facilities, such as facility expansions and increases in the maximum operating pressure, must be approved by the TRRC through an amendment to the facility’s existing permit. In addition, the TRRC must approve transfers of the permits. Texas laws and regulations also require all natural gas storage facilities to be operated to prevent waste, the uncontrolled escape of gas, pollution and danger to life or property. Accordingly, the TRRC requires natural gas storage facilities to implement certain safety, monitoring, reporting and record-keeping measures.
Violations of the terms and provisions of a TRRC permit or a TRRC order or regulation can result in the modification, cancellation or suspension of an operating permit and/or civil penalties, injunctive relief, or both.
The states in which ETP and Regency conduct operations administer federal pipeline safety standards under the Pipeline Safety Act of 1968 (“Pipeline Safety Act”) which requires certain pipeline companies to comply with safety standards in constructing and operating the pipelines, and subjects pipelines to regular inspections. Some of ETP’s gathering facilities are exempt from the requirements of the Pipeline Safety Act. In respect to recent pipeline accidents in other parts of the country, Congress and the DOT are considering heightened pipeline safety requirements.
Failure to comply with applicable laws and regulations could result in the imposition of administrative, civil and criminal remedies.
ETP’s and Regency’s interstate pipelines are subject to laws, regulations and policies governing the rates they are allowed to charge for their services.
Laws, regulations and policies governing interstate natural gas pipeline rates could affect the ability of ETP’s and Regency’s interstate pipelines to establish rates, to charge rates that would cover future increases in its costs, or to continue to collect rates that cover current costs. NGA-jurisdictional natural gas companies must charge rates that are deemed just and reasonable by FERC. The rates charged by natural gas companies are generally required to be on file with FERC in FERC-approved tariffs. Pursuant to the NGA, existing tariff rates may be challenged by complaint and rate increases proposed by the natural gas company may be challenged by protest. ETP and Regency also may be limited by the terms of negotiated rate agreements from seeking future rate increases, or constrained by competitive factors from charging its FERC-approved maximum just and reasonable rates. Further, the FERC has the ability, on a prospective basis, order refunds of amounts collected under rates that have been found by FERC to be in excess of a just and reasonable level.
On September 21, 2011, in lieu of filing a new general rate case filing under Section 4 of the NGA, Transwestern filed a proposed settlement with the FERC, which was approved by the FERC on October 31, 2011. Transwestern is required to file a new general rate case on October 1, 2014. However, shippers which were not parties to the settlement have the right to challenge the lawfulness of tariff rates that have become final and effective. FERC may also investigate such rates on its own initiative.
Some of the shippers on ETP and Regency's interstate pipelines pay rates established pursuant to long-term, negotiated rate transportation agreements. Prospective shippers on interstate pipelines that elect not to pay a negotiated rate for service may

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instead choose to pay a cost-based recourse rate. Negotiated rate agreements generally provide a degree of certainty to the pipeline and shipper as to a fixed rate during the term of the relevant transportation agreement, but such agreements can limit the pipeline’s future ability to collect costs associated with construction and operation of the pipeline that might be higher than anticipated at the time the negotiated rate agreement was entered.
Any successful challenge to the rates of ETP’s or Regency’s interstate natural gas companies, whether the result of complaint, protest or investigation, could reduce its revenues associated with providing transportation services on a prospective basis. We, ETP and Regency cannot assure Unitholders that ETP’s or Regency’s interstate pipelines will be able to recover all of their costs through existing or future rates.
The ability of interstate pipelines held in tax-pass-through entities, like ETP and Regency, to include an allowance for income taxes in their regulated rates has been subject to extensive litigation before FERC and the courts, and the FERC’s current policy is subject to future refinement or change.
The ability of interstate pipelines held in tax-pass-through entities, like ETP and Regency, to include an allowance for income taxes as a cost-of-service element in their regulated rates has been subject to extensive litigation before FERC and the courts for a number of years. It is currently FERC’s policy to permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential income tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. Under the FERC’s policy, ETP and Regency thus remain eligible to include an income tax allowance in the tariff rates their interstate pipelines charge for interstate natural gas transportation. The application of that policy remains subject to future refinement or change by FERC. With regard to rates charged and collected by Transwestern, the allowance for income taxes as a cost-of-service element in ETP’s tariff rates is generally not subject to challenge prior to the end of the term of its 2011 rate case settlement.
The interstate pipelines are subject to laws, regulations and policies governing terms and conditions of service, which could adversely affect their business and operations.
In addition to rate oversight, the FERC’s regulatory authority extends to many other aspects of the business and operations of ETP’s and Regency’s interstate pipelines, including:
operating terms and conditions of service;
the types of services interstate pipelines may offer their customers;
construction of new facilities;
acquisition, extension or abandonment of services or facilities;
reporting and information posting requirements;
accounts and records; and
relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.
Compliance with these requirements can be costly and burdensome. Future changes to laws, regulations and policies in these areas may impair the ability of ETP’s and Regency’s interstate pipelines to compete for business, may impair their ability to recover costs or may increase the cost and burden of operation.
ETP and Regency must on occasion rely upon rulings by the FERC or other governmental authorities to carry out certain of their business plans. For example, in order to carry out its plan to construct the Fayetteville Express and Tiger pipelines ETP was required to, among other things, file and support before the FERC NGA Section 7(c) applications for certificates of public convenience and necessity to build, own and operate such facilities. ETP and Regency cannot guarantee that FERC will authorize construction and operation of any future interstate natural gas transportation project it might propose. ETP and Regency are required to attain approval from the FERC for expansions of their pipeline facilities. ETP cannot guarantee that the FERC will authorize any future interstate natural gas transportation project ETP might propose. Moreover, there is no guarantee that certificate authority for interstate projects will be granted in a timely manner or without being subject to potentially burdensome conditions.
Similarly, MEP was required to obtain from FERC a certificate of public convenience and necessity to build, own and operate the Midcontinent Express pipeline. Although the FERC has granted such certificate authority, the FERC’s certificate order is currently pending judicial review before the United States Court of Appeals for the District of Columbia Circuit. ETP and Regency cannot give any assurance that the court will affirm, in all material respects, the FERC’s July 25, 2008 Midcontinent Express certificate order, or that the FERC will not materially alter the certificate order on any remand that might be ordered by the court. There are also pending requests for rehearing related to certain of the FERC’s post-certification orders related to the Midcontinent Express

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project. ETP and Regency cannot guarantee that these post-certification orders will not be altered on rehearing or that these orders will not be subject to judicial review.
Failure to comply with all applicable FERC-administered statutes, rules, regulations and orders, could bring substantial penalties and fines. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation. FERC possesses similar authority under the NGPA.
Finally, we, ETP and Regency cannot give any assurance regarding the likely future regulations under which ETP or Regency will operate its interstate pipelines or the effect such regulation could have on its business, financial condition, and results of operations.
A change in the characterization of some of ETP’s or Regency’s assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation and cost.
The distinction between FERC-regulated transmission service and intrastate transportation or gathering services is the subject of regular litigation at FERC and in the courts and of policy discussions at FERC. The classification and regulation of some of the ETP or Regency gathering facilities or intrastate transportation pipelines may be subject to change based on future determinations by FERC, the courts, or Congress. Such a change could result in increased regulation by FERC, which may cause revenues to decline and operating expenses to increase.
ETP’s and Regency’s businesses involve hazardous substances and may be adversely affected by environmental regulation.
ETP’s and Regency’s natural gas and NGL operations are subject to stringent federal, state and local laws and regulations that seek to protect human health and the environment, including those governing the emission or discharge of materials into the environment. These laws and regulations may require the acquisition of permits for ETP’s and Regency’s operations, result in capital expenditures to manage, limit, or prevent emissions, discharges or releases of various materials from ETP’s and Regency’s pipelines, plants and facilities and impose substantial liabilities for pollution resulting from ETP’s and Regency’s operations. Several governmental authorities, such as the EPA have the power to enforce compliance with these laws and regulations and the permits issued under them and frequently mandate difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations and permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctive relief.
ETP and Regency may incur substantial environmental costs and liabilities because of the underlying risk inherent to its operations. Certain environmental laws and regulations can provide for joint and several strict liability for cleanup to address discharges or releases of petroleum hydrocarbons or other materials or wastes at sites to which ETP or Regency may have sent wastes or on, under, or from ETP’s and Regency’s properties and facilities, many of which have been used for industrial activities for a number of years, even if such discharges were caused by ETP’s and Regency’s respective predecessors. Private parties, including the owners of properties through which ETP’s and Regency’s gathering systems pass or facilities where their petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. For example, the total accrued future estimated cost of remediation activities relating to ETP’s Transwestern pipeline operations was approximately $5.7 million as of December 31, 2011, which is included in the aggregate environmental accruals, and such activities are expected to continue through 2025.
Changes in environmental laws and regulations occur frequently, and changes that result in significantly more stringent and costly waste handling, emission standards, or storage, transport, disposal or remediation requirements could have a material adverse effect on ETP’s and Regency’s operations or financial position. For example, the EPA in 2008 lowered the federal ozone standard from 0.08 ppm to 0.075 ppm, requiring the environmental agencies in states with areas that do not currently meet this standard to adopt new rules to further reduce NOx and other ozone precursor emissions. ETP and Regency have previously been able to satisfy the more stringent NOx emission reduction requirements that affect its compressor units in ozone non-attainment areas at reasonable cost, but there is no guarantee that the changes ETP or Regency may have to make in the future to meet the new ozone standard or other evolving standards will not require it to incur costs that could be material to its operations.
Recently proposed rules regulating air emissions from oil and natural gas operations could cause us to incur increased capital expenditures and operating costs, which may be significant.
On July 28, 2011, the U.S. Environmental Protection Agency ("EPA") proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA's proposed rule package includes New Source Performance Standards ("NSPS") to address emissions of sulfur dioxide and volatile organic compounds ("VOCs"), and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA's proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of "green completions" for hydraulic fracturing, which requires the operator to recover rather than

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vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. The EPA must take final action on the proposed rules by February 28, 2012. If finalized, these rules could require a number of modifications to ETP's or Regency's operations including the installation of new equipment. Compliance with such rules will be required within three years of publication of the final rules, and it could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact ETP's or Regency's businesses.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas and other hydrocarbon products that ETP and Regency transport, store or otherwise handle in connection with their transportation, storage, and midstream services.
In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” 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 greenhouse gases under existing provisions of the federal Clean Air Act. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA’s rules relating to emissions of greenhouse gases 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.
In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas 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 greenhouse gas emission reduction goal.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require ETP or Regency 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, natural gas or NGLs. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on ETP’s or Regency’s businesses, financial conditions and results of operations.
Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such effects were to occur, the operations of ETP and Regency could be adversely affected in various ways, including damages to their facilities from powerful winds or rising waters, or increased costs for insurance. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for ETP’s and Regency’s natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that ETP and Regency produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for ETP’s and Regency’s fuels could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on the business of ETP and Regency.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could slow ETP’s and Regency’s customers’ development of shale gas supplies.
Congress is considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing is an important and commonly used process in the completion of unconventional natural gas wells in shale formations. This process involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of these bills, which are pending in the Energy and Commerce Committee and the Environmental and Public Works Committee of the House of Representatives and Senate, respectively, have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that chemicals used in the fracturing process had adversely affected groundwater. If adopted, these bills also would

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establish additional federal permitting and regulatory requirements that could lead to operational delays or increased operating costs. In addition, the EPA recently announced that it was beginning a comprehensive research study on the potential impacts that hydraulic fracturing may have on water quality and public health. Consequently, even if the introduced bills are not enacted, EPA’s study could spur further action at a later date toward additional federal legislation and regulation of hydraulic fracturing activities. Legislative and regulatory initiatives have also arisen in several states, including New York and Pennsylvania. By slowing the pace of natural gas development, the imposition of additional regulatory requirements on hydraulic fracturing could affect the financial performance of ETP’s and Regency’s existing and planned pipeline systems, particularly those serving the Barnett and Haynesville production areas or other shale gas plays.
Any reduction in the capacity of, or the allocations to, ETP’s and Regency’s shippers in interconnecting, third-party pipelines could cause a reduction of volumes transported in ETP’s and Regency’s pipelines, which would adversely affect revenues and cash flow.
Users of ETP’s and Regency’s pipelines are dependent upon connections to and from third-party pipelines to receive and deliver natural gas and NGLs. Any reduction in the capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes being transported in ETP’s and Regency’s pipelines. Similarly, if additional shippers begin transporting volumes of natural gas and NGLs over interconnecting pipelines, the allocations to existing shippers in these pipelines would be reduced, which could also reduce volumes transported in ETP’s and Regency’s pipelines. Any reduction in volumes transported in ETP’s and Regency’s pipelines would adversely affect their revenues and cash flow.
ETP and Regency encounter competition from other midstream and transportation and storage companies.
ETP and Regency compete with similar enterprises in each of their areas of operations. Some of their competitors are large oil, natural gas, gathering and processing and natural gas pipeline companies that have greater financial resources and access to supplies of natural gas. In addition, ETP’s and Regency’s customers who are significant producers or consumers of NGLs may develop their own processing facilities in lieu of using those of ETP or Regency. Similarly, competitors may establish new connections with pipeline systems that would create additional competition for services that ETP and Regency provide to their customers. ETP’s and Regency’s ability to renew or replace existing contracts with their customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of their competitors.
The Transwestern, Midcontinent Express, Fayetteville Express, Tiger and Gulf States pipelines compete with other interstate and intrastate pipeline companies in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service and the flexibility and reliability of service. Natural gas competes with other forms of energy available to ETP’s and Regency’s customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the capability to convert to alternate fuels and other factors, including weather and natural gas storage levels, affect the levels of natural gas transportation volumes in the areas served by ETP’s and Regency’s pipelines.
The natural gas contract compression business is highly competitive, and there are low barriers to entry for individual projects. In addition, some of Regency’s competitors are large national and multinational companies that have greater financial and other resources. Regency’s ability to renew or replace existing contracts with its customers at rates sufficient to maintain current revenue and cash flows could be adversely affected by the activities of its competitors and its customers. If Regency’s competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, Regency may be unable to compete effectively. Some of these competitors may expand or construct newer or more powerful compressor fleets that would create additional competition for Regency. In addition, Regency’s customers that are significant producers of natural gas and crude oil may purchase and operate their own compressor fleets in lieu of using Regency’s natural gas contract compression services. All of these competitive pressures could have a material adverse effect on Regency’s business, results of operations, and financial condition.
The inability to continue to access tribal lands could adversely affect Transwestern’s ability to operate its pipeline system and the inability to recover the cost of right-of-way grants on tribal lands could adversely affect its financial results.
Transwestern’s ability to operate its pipeline system on certain lands held in trust by the United States for the benefit of a Native American tribe, which we refer to as tribal lands, will depend on its success in maintaining existing rights-of-way and obtaining new rights-of-way on those tribal lands. Securing extensions of existing and any additional rights-of-way is also critical to Transwestern’s ability to pursue expansion projects. We cannot provide any assurance that Transwestern will be able to acquire new rights-of-way on tribal lands or maintain access to existing rights-of-way upon the expiration of the current grants. ETP’s financial position could be adversely affected if the costs of new or extended right-of-way grants cannot be recovered in rates. Transwestern’s existing right-of-way agreements with the Navajo Nation, Southern Ute, Pueblo of Laguna and Fort Mojave tribes extend through November 2029, September 2020, December 2022 and April 2019, respectively.

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ETP and Regency may be unable to bypass the processing plants, which could expose them to the risk of unfavorable processing margins.
ETP and Regency can generally elect to bypass their respective processing plants when processing margins are unfavorable and instead deliver pipeline-quality gas by blending rich gas from the gathering systems with lean gas transported on the their other gathering pipelines and systems. In some circumstances, such as when ETP and Regency do not have a sufficient amount of lean gas to blend with the volume of rich gas that they receive at the processing plant, ETP and Regency may have to process the rich gas. If ETP or Regency has to process gas when processing margins are unfavorable, its results of operations will be adversely affected.
ETP and Regency may be unable to retain existing customers or secure new customers, which would reduce their revenues and limit its future profitability.
The renewal or replacement of existing contracts with ETP’s and Regency’s customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond its control, including competition from other pipelines, and the price of, and demand for, natural gas in the markets ETP and Regency serve.
As a consequence of the increase in competition in the industry and volatility of natural gas prices, end-users and utilities are increasingly reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are many companies of greatly varying size and financial capacity that compete with ETP and Regency in the marketing of natural gas, ETP and Regency often compete in the end-user and utilities markets primarily on the basis of price. The inability of ETP’s or Regency’s management to renew or replace its current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on ETP’s or Regency’s profitability.
ETP’s natural gas storage business may depend on neighboring pipelines to transport natural gas.
To obtain natural gas, ETP’s natural gas storage business depends on the pipelines to which they have access. Many of these pipelines are owned by parties not affiliated with ETP or Regency. Any interruption of service on those pipelines or adverse change in their terms and conditions of service could have a material adverse effect on ETP’s or Regency’s ability, and the ability of its customers, to transport natural gas to and from its facilities and a corresponding material adverse effect on ETP’s storage revenues. In addition, the rates charged by those interconnected pipelines for transportation to and from ETP’s facilities affect the utilization and value of its storage services. Significant changes in the rates charged by those pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on ETP’s storage revenues.
ETP’s and Regency’s pipeline integrity programs may cause them to incur significant costs and liabilities.
ETP’s and Regency’s pipeline operations are subject to regulation by the DOT, under the Pipeline Hazardous Materials Safety Administration (“PHMSA”) pursuant to which the PHMSA has established regulations relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Based on the results of ETP’s current pipeline integrity testing programs, ETP estimates that compliance with these federal regulations and analogous state pipeline integrity requirements will result in capital costs of $3.4 million and operating and maintenance costs of $17.9 million over the course of the next year, while Regency estimates that compliance with these federal regulations and analogous state pipeline integrity requirements will results in $0.8 million. For the years ended December 31, 2011, 2010 and 2009, $18.3 million, $13.3 million and $31.4 million, respectively, of capital costs and $14.7 million, $15.4 million and $18.5 million, respectively, of operating and maintenance costs have been incurred for pipeline integrity testing by ETP. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause ETP or Regency to incur material capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of their pipelines.
Changes in other forms of health and safety regulations are also being considered. New pipeline safety legislation requiring more stringent spill reporting and disclosure obligations has been introduced in the U.S. Congress and was passed by the U.S. House of Representatives in 2010, but was not voted on in the U.S. Senate. Similar legislation is likely to be considered in the current session of Congress. The DOT has also recently proposed legislation providing for more stringent oversight of pipelines and increased penalties for violations of safety rules, which is in addition to the PHMSA’s announced intention to strengthen its rules.

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Such Legislative and regulatory changes could have a material effect on ETP’s or Regency’s operations through more stringent and comprehensive safety regulations and higher penalties for the violation of those regulations.
A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail ETP’s and Regency’s operations and otherwise materially adversely affect their cash flow.
Some of ETP’s and Regency’s operations involve risks of personal injury, property damage and environmental damage, which could curtail its operations and otherwise materially adversely affect its cash flow. For example, natural gas facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch. Virtually all of ETP’s and Regency’s operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes.
If one or more facilities that are owned by ETP or Regency or that deliver natural gas or other products to ETP or Regency are damaged by severe weather or any other disaster, accident, catastrophe or event, ETP’s or Regency’s operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply ETP’s or Regency’s facilities or other stoppages arising from factors beyond its control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the revenues generated by ETP’s or Regency’s operations, or which causes it to make significant expenditures not covered by insurance, could reduce ETP’s or Regency’s cash available for paying distributions to its Unitholders, including us.
As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, ETP and Regency may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If ETP or Regency were to incur a significant liability for which it was not fully insured, it could have a material adverse effect on ETP’s or Regency’s financial position and results of operations, as applicable. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.
Terrorist attacks aimed at ETP’s or Regency’s facilities could adversely affect its business, results of operations, cash flows and financial condition.
Since the September 11, 2001 terrorist attacks on the United States, the United States government has issued warnings that energy assets, including the nation’s pipeline infrastructure, may be the future target of terrorist organizations. Any terrorist attack on ETP’s or Regency’s facilities or pipelines or those of its customers could have a material adverse effect on ETP’s or Regency’s business, as applicable.
ETP has a significant equity investment in AmeriGas and the value of this investment, and the cash distributions ETP expects to receive from this investment, are subject to the risks encountered by AmeriGas with respect to its business.
In January 2012, ETP consummated the contribution of its Propane Business to AmeriGas in exchange for consideration of approximately $1.46 billion in cash and approximately 29.6 million AmeriGas common units, plus the assumption of approximately $71 million of existing HOLP debt. The value of ETP's investment in AmeriGas common units and the cash distributions it expects to receive on a quarterly basis with respect to these common units, are subject to the risks encountered by AmeriGas with respect to its business, including the following:
adverse weather condition resulting in reduced demand;
cost volatility and availability of propane, and the capacity to transport propane to its customers;
the availability of, and its ability to consummate, acquisition or combination opportunities;
successful integration and future performance of acquired assets or businesses;
changes in laws and regulations, including safety, tax, consumer protection and accounting matters;
competitive pressures from the same and alternative energy sources;
failure to acquire new customers and retain current customers thereby reducing or limiting any increase in revenues;
liability for environmental claims;
increased customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand;
adverse labor relations;
large customer, counter-party or supplier defaults;

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liability in excess of insurance coverage for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to transporting, storing and distributing propane, butane and ammonia;
political, regulatory and economic conditions in the United States and foreign countries;
capital market conditions, including reduced access to capital markets and interest rate fluctuations;
changes in commodity market prices resulting in significantly higher cash collateral requirements;
the impact of pending and future legal proceedings;
the timing and success of its acquisitions and investments to grow its business; and
its ability to successfully integrate acquired businesses and achieve anticipated synergies.
Regency’s contract compression operations depend on particular suppliers and is vulnerable to parts and equipment shortages and price increases, which could have a negative impact on its results of operations.
The principal manufacturers of components for Regency’s natural gas compression equipment include Caterpillar, Inc. for engines, Air-X-Changers for coolers, and Ariel Corporation for compressors and frames. Regency’s reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of required components in a timely manner. Regency also relies primarily on two vendors, Spitzer Industries Corp. and Standard Equipment Corp., to package and assemble its compression units. Regency does not have long-term contracts with these suppliers or packagers, and a partial or complete loss of certain of these sources could have a negative impact on Regency’s results of operations and could damage its customer relationships. In addition, since Regency expects any increase in component prices for compression equipment or packaging costs will be passed on to Regency, a significant increase in their pricing could have a negative impact on Regency’s results of operations.
The recent adoption of financial reform legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The United States Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173) in 2010, which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. This legislation requires the Commodities Futures Trading Commission (the “CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In December 2011, the CFTC extended temporary exemptive relief from certain swap regulation provisions of the legislation until July 16, 2012. The CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. It is not possible at this time to predict when the CFTC make these regulations effective. The legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our 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 our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure its existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable.
ETP and Regency do not control, and therefore may not be able to cause or prevent certain actions by, certain of their joint ventures.
Certain of ETP’s and Regency’s joint ventures have their own governing boards, and ETP or Regency may not control all of the decisions of those boards. Consequently, it may be difficult or impossible for ETP or Regency to cause the joint venture entity to take actions that ETP or Regency believe would be in their or the joint venture’s best interests. Likewise, ETP or Regency may be unable to prevent actions of the joint venture.
The profitability of certain activities in ETP’s or Regency’s NGL and refined products storage business, NGL transportation business and off-gas processing and fractionating business are largely dependent upon market demand for NGLs and refined products, which has been volatile, and competition in the market place, both of which are factors that are beyond our control.
ETP’s and Regency’s NGL and refined products storage revenues are primarily derived from fixed capacity arrangements between ETP or Regency and their customers. However, a portion of ETP’s and Regency’s revenue is derived from fungible storage and throughput arrangements, under which revenue is more dependent upon demand for storage from customers. Demand for these

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services may fluctuate as a result of changes in commodity prices. ETP’s and Regency’s NGL and refined products storage assets are primarily located in the Mont Belvieu area, which is a significant storage distribution and trading complex with multiple industry participants, any one of which could compete for the business of ETP’s and Regency’s existing and potential customers. Any loss of business from existing customers or ETP’s or Regency’s inability to attract new customers could have an adverse effect on our results of operations.
Revenue from ETP’s and Regency’s NGL transportation systems is exposed to risks due to fluctuations in demand for transportation as a result of unfavorable commodity prices and competition from nearby pipelines. ETP and Regency receive substantially all of their transportation revenues through dedicated contracts under which the customer agrees to deliver the total output from particular processing plants that are connected only to ETP’s or Regency’s transportation system. ETP or Regency may not be able to renew these contracts or execute new customer contracts on favorable terms if NGL prices decline and demand for ETP’s or Regency’s transportation services decreases. Any loss of existing customers due to decreased demand for ETP’s or Regency’s services or competition from other transportation service providers could have a negative impact on our revenues and have an adverse effect on our results of operations.
Revenue from ETP’s and Regency’s off-gas processing and fractionating system in south Louisiana is exposed to risks due to the low concentration of suppliers near the facilities and the possibility that connected refineries may not provide ETP or Regency with sufficient off-gas for processing at their facilities. The connected refineries may also experience outages due to maintenance issues and severe weather, such as hurricanes. ETP and Regency receive revenues primarily through customer agreements that are a combination of keep-whole and percent-of-proceeds arrangements, as well as from transportation and fractionation fees. Consequently, a large portion of ETP’s and Regency’s off-gas processing and fractionation revenue is exposed to risks due to fluctuations in commodity prices. In addition, a decline in NGL prices could cause a decrease in demand for ETP’s or Regency’s off-gas processing and fractionation services and could have an adverse effect on our results of operations.
The markets and prices for natural gas and NGLs depend upon factors beyond our control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions, and other factors, including:
the impact of weather on the demand for oil, natural gas and NGLs;
the level of domestic oil and natural gas production;
the availability of imported oil, natural gas and NGLs;
actions taken by foreign oil and gas producing nations;
the availability of local transportation systems;
the price, availability and marketing of competitive fuels;
the demand for electricity;
the impact of energy conservation efforts; and
the extent of governmental regulation and taxation.
ETP's and Regency's pipelines may be subject to more stringent safety regulation.
On January 3, 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, became effective. The new law requires more stringent oversight of pipelines and increased civil penalties for violations of pipeline safety rules. The law requires numerous studies and/or the development of rules over the next two years covering the expansion of integrity management, use of automatic and remote-controlled shut-off valves, leak detection systems, sufficiency of existing regulation of gathering pipelines, use of excess flow valves, verification of maximum allowable operating pressure, incident notification, and other pipeline-safety related rules. The DOT has already proposed rules that address many areas of the newly adopted legislation. Any regulatory changes could have a material effect on ETP's or Regency's operations through more stringent and comprehensive safety regulations and higher penalties for the violation of those regulations.
Certain of ETP’s and Regency’s assets may become subject to regulation.
Intrastate transportation of NGLs is largely regulated by the state in which such transportation takes place. The West Texas pipeline, which ETP and Regency acquired as part the LDH acquisition, transports NGLs within the state of Texas and is subject to regulation by the Texas Railroad Commission (“TRRC”). This NGL transportation system offers services pursuant to an intrastate transportation tariff on file with the TRRC. Such services must be provided in a manner that is just, reasonable and non-discriminatory. ETP and Regency believe that this NGL system does not currently provide interstate service and that it is thus not subject to FERC jurisdiction under the Interstate Commerce Act (the "ICA") and the Energy Policy Act of 1992. We cannot guarantee that the jurisdictional status of this NGL pipeline system will remain unchanged. If the West Texas pipeline became

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subject to regulation by the FERC, pursuant to the ICA, the FERC’s rate-making methodologies may, among other things, delay the use of rates that reflect increased costs and subject ETP or Regency to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect revenues and cash flow related to these assets.
Tax Risks to Common Unitholders
Our tax treatment depends on our continuing status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of additional entity-level taxation by individual states. If the IRS were to treat us, ETP or Regency as a corporation for federal income tax purposes or if we, ETP or Regency become subject to a material amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to Unitholders.
The anticipated after-tax economic benefit of an investment in our Common Units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this matter. The value of our investments in ETP and Regency depends largely on ETP and Regency being treated as partnerships for federal income tax purposes.
Despite the fact that we, ETP and Regency are each a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. If we are so treated, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and we would likely pay additional state income taxes as well. If ETP or Regency were treated as a corporation for federal income tax purposes for any taxable year for which the statute of limitations remains open or for any future taxable year, it would pay federal income tax on its taxable income at the corporate tax rate. Distributions to us would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to us. As a result, there would be a material reduction in the anticipated cash flow. In either case, our available cash would be substantially reduced.
The present tax treatment of publicly traded partnerships, including us, or an investment in our Common Units, may be modified by administrative, legislative or judicial interpretation at any time, causing us or our subsidiaries to be treated as a corporation for federal income tax purposes or otherwise subjecting us or our subsidiaries to entity-level taxation. For example, recently, members of the U.S. Congress considered substantive changes to the U.S. federal income tax laws that would have affected the tax treatment of certain publicly traded partnerships. Several states currently impose entity-level taxes on partnerships, including us. Further, because of widespread state budget deficits and other reasons, several additional states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and other forms of taxation. If any additional states were to impose a tax upon us or our subsidiaries as an entity, our cash available for distribution would be reduced. Any modification to the U.S. federal income or state tax laws, or interpretations thereof, may or may not be applied retroactively. Although we are unable to predict whether any of these changes or any other proposals will be reintroduced or will ultimately be enacted, any such changes could negatively impact the value of an investment in our Common Units or the Common Units of ETP or Regency.
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or to additional taxation as an entity for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
The tax treatment of our structure is subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The U.S. federal income tax treatment of Unitholders depends in some instances on determinations of fact and interpretations of complex provisions of U.S. federal income tax law. The U.S. federal income tax rules are constantly under review by persons involved in the legislative process, the IRS, and the U.S. Treasury Department, frequently resulting in revised interpretations of established concepts, statutory changes, revisions to Treasury Regulations and other modifications and interpretations. The present U.S. federal income tax treatment of an investment in our Common Units may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation (referred to as the “Qualifying Income Exception”), affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our Common Units. For example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Internal Revenue Code section 7704(d). It is possible that these efforts could result in changes to the existing U.S. federal tax laws that affect publicly traded partnerships, including us. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our Common Units as well as the value of an investment in ETP and Regency Common Units.

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If the IRS contests the federal income tax positions we or our subsidiaries take, the market for our Common Units, ETP Common Units or Regency Common Units may be adversely affected and the costs of any such contest will reduce cash available for distributions to our Unitholders.
Neither we nor our subsidiaries have requested a ruling from IRS with respect to our treatment as partnerships for federal income tax purposes. The IRS may adopt positions that differ from the positions we or our subsidiaries take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we or our subsidiaries take. A court may not agree with some or all of the positions we or our subsidiaries take. Any contest with the IRS may materially and adversely impact the market for our Common Units, ETP’s Common Units or Regency’s Common Units and the prices at which they trade. In addition, the costs of any contest with the IRS will be borne by us or our subsidiaries, and therefore indirectly by us, as a Unitholder and as the owner of the general partner of interests in ETP and Regency, reducing the cash available for distribution to our Unitholders.
Unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Because our Unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, Unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from the taxation of their share of our taxable income.
Tax gain or loss on disposition of our Common Units could be more or less than expected.
If Unitholders sell their Common Units, they will recognize a gain or loss equal to the difference between the amount realized and the tax basis in those Common Units. Because distributions in excess of the Unitholder’s allocable share of our net taxable income decrease the Unitholder’s tax basis in their Common Units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to the Unitholder if they sell such units at a price greater than their adjusted tax basis in those units, even if the price received is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a Unitholder’s share of our nonrecourse liabilities, if a Unitholder sells units, the Unitholders may incur a tax liability in excess of the amount of cash received from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning Common Units that may result in adverse tax consequences to them.
Investment in Common Units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs) and non-U.S. persons raises tax issues unique to them. For example, virtually all of our income allocated to Unitholders who are organizations exempt from federal income tax, may be taxable to them as “unrelated business taxable income.” Distributions to non-U.S. persons will be reduced by withholding taxes, generally at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal and state income tax returns and generally pay United States federal and state income tax on their share of our taxable income and on gains realized on the sale of our units.
We treat each purchaser of Common Units as having the same tax benefits without regard to the actual Common Units purchased. The IRS may challenge this treatment, which could result in a Unitholder owing more tax and may adversely affect the value of the Common Units.
The IRS may challenge the manner in which we calculate our Unitholder’s basis adjustment under Section 743(b) of the Internal Revenue Code. If so, because neither we nor a Unitholder can identify the units to which this issue relates once the initial holder has traded them, the IRS may assert adjustments to all Unitholders selling units within the period under audit as if all Unitholders owned such units.
Any position we take that is inconsistent with applicable Treasury Regulations may have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our Unitholders.
A successful IRS challenge to this position or other positions we may take could adversely affect the amount of taxable income or loss allocated to our Unitholders. It also could affect the gain from a Unitholder’s sale of Common Units and could have a negative impact on the value of the Common Units or result in audit adjustments to our Unitholders’ tax returns without the benefit of additional deductions. Moreover, because one of our subsidiaries that is organized as a C corporation for federal income tax purposes owns units in ETP, a successful IRS challenge could result in this subsidiary having a greater tax liability than we anticipate and, therefore, reduce the cash available for distribution to our partnership and, in turn, to our Unitholders.

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We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our Unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A Unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the Unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because a Unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, the Unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the Unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the Unitholder and any cash distributions received by the Unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
ETP and Regency have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between us and the public Unitholders of ETP and Regency. The IRS may challenge this treatment, which could adversely affect the value of ETP’s or Regency’s Common Units and our Common Units.
When we, ETP or Regency issue additional units or engage in certain other transactions, we, ETP or Regency determine the fair market value of the assets and allocate any unrealized gain or loss attributable to such assets to the capital accounts of ETP’s and Regency’s Unitholders and us. Although ETP and Regency may from time to time consult with professional appraisers regarding valuation matters, including the valuation of its assets, ETP and Regency make many of the fair market value estimates of their assets themselves using a methodology based on the market value of their Common Units as a means to measure the fair market value of their assets. ETP’s or Regency’s methodology may be viewed as understating the value of ETP’s or Regency’s assets. In that case, there may be a shift of income, gain, loss and deduction between certain ETP or Regency Unitholders and us, which may be unfavorable to such ETP or Regency Unitholders. Moreover, under our current valuation methods, subsequent purchasers of our Common Units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to ETP’s or Regency’s tangible assets and a lesser portion allocated to ETP’s or Regency’s intangible assets. The IRS may challenge ETP’s or Regency’s valuation methods, or our, ETP’s or Regency’s allocation of Section 743(b) adjustment attributable to ETP’s or Regency’s tangible and intangible assets, and allocations of income, gain, loss and deduction between us and certain of ETP’s or Regency’s Unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our Unitholders, the ETP Unitholders or the Regency Unitholders. It also could affect the amount of gain on the sale of Common Units by our Unitholders, ETP’s Unitholders or Regency’s Unitholders and could have a negative impact on the value of our Common Units or those of ETP or Regency or result in audit adjustments to the tax returns of our, ETP’s or Regency’s Unitholders without the benefit of additional deductions.
The sale or exchange of 50% or more of our capital and profits interests during any twelve month period will result in the termination of our partnership for federal income tax purposes.
We will be considered technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same unit during the applicable twelve-month period will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all Unitholders which would require us to file two federal partnership tax returns for one fiscal year, and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a Unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in such Unitholder’s taxable income for the year of termination. A technical termination currently would not affect our classification as a partnership

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for federal income tax purposes. We would be treated as a new partnership for tax purposes on the technical termination date, and would be required to make new tax elections and could be subject to penalties if we were unable to determine in a timely manner that a termination occurred.
Unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our Common Units.
In addition to federal income taxes, the Unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we, ETP or Regency conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. We currently own property or conduct business in more than 40 states, either directly or indirectly as a result of ETP's investment in AmeriGas. Most of these states impose an income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal or corporate income tax. Unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of the jurisdictions. Further, Unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of each Unitholder to file all federal, state and local tax returns.
Risks Related to ETE’s Acquisition of Southern Union Company (“SUG Merger”)
The failure to successfully combine the businesses of ETE and Southern Union Company (“Southern Union”) in the expected time frame may adversely affect ETE’s future results.
The success of the SUG Merger will depend, in part, on the ability of ETE to realize the anticipated benefits from combining the businesses of ETE and Southern Union. To realize these anticipated benefits, ETE’s and Southern Union’s businesses must be successfully combined. If the combined company is not able to achieve these objectives, the anticipated benefits of the SUG Merger may not be realized fully or at all or may take longer to realize than expected. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the SUG Merger.
ETE and Southern Union, including their respective subsidiaries, have operated and, until the completion of the SUG Merger, will continue to operate independently. It is possible that the integration process could result in the loss of key employees, as well as the disruption of each company’s ongoing businesses or inconsistencies in their standards, controls, procedures and policies. Any or all of those occurrences could adversely affect ETE’s ability to maintain relationships with customers and employees after the SUG Merger or to achieve the anticipated benefits of the SUG Merger. Integration efforts between the two companies will also divert management attention and resources. These integration matters could have an adverse effect on each of ETE and Southern Union.
The completion of the SUG Merger is subject to the satisfaction of certain conditions to closing, and the date that the SUG Merger would be consummated is uncertain.
The completion of the SUG Merger is subject to the absence of a material adverse change to the business or results of operation of ETE and SUG, the receipt of necessary regulatory approvals and the satisfaction or waiver of other conditions specified in the merger agreement related to the SUG transaction. In the event those conditions to closing are not satisfied or waived, we would not complete the SUG Merger.
While we expect to complete the SUG Merger in the first quarter of 2012, the completion date of the SUG Merger might be later than expected due to delays in obtaining required regulatory approvals or other unforeseen events.
The pendency of the SUG Merger could materially adversely affect the future business and operations of ETE or Southern Union or result in a loss of Southern Union employees.
In connection with the pending SUG Merger, it is possible that some customers, suppliers and other persons with whom ETE, ETE’s subsidiaries or Southern Union have a business relationship may delay or defer certain business decisions or might decide to seek to terminate, change or renegotiate their relationship with Southern Union as a result of the SUG Merger, which could negatively impact revenues, earnings and cash flows of ETE or Southern Union, as well as the market prices of ETE common units or shares of Southern Union common stock, regardless of whether the SUG Merger is completed. Similarly, current and prospective employees of Southern Union may experience uncertainty about their future roles with ETE and Southern Union following completion of the SUG Merger, which may materially adversely affect the ability of ETE and Southern Union to attract and retain key employees.

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Failure to complete the SUG Merger could negatively impact the unit price of ETE and its respective future businesses and financial results.
If the SUG Merger is not completed, the ongoing business of ETE may be adversely affected and ETE will be subject to several risks and consequences, including the following:
ETE will be required to pay certain costs relating to the SUG Merger, whether or not the SUG Merger is completed, such as legal, accounting, financial advisor and printing fees;
ETE would not realize the expected benefits of the SUG Merger;
under the merger agreement, ETE is subject to certain restrictions on the conduct of its business prior to completing the SUG Merger which may adversely affect its ability to execute certain of its business strategies; and
matters relating to the SUG Merger may require substantial commitments of time and resources by ETE management, which could otherwise have been devoted to other opportunities that may have been beneficial to ETE.
In addition, if the SUG Merger is not completed, ETE may experience negative reactions from the financial markets and from their respective customers and employees. ETE also could be subject to litigation related to any failure to complete the SUG Merger or to enforcement proceedings commenced against ETE to attempt to force it to perform its obligations under the merger agreement.
The completion of the SUG Merger will require ETE to enter into a new financing arrangement. If ETE’s financing for the SUG Merger becomes unavailable, the SUG Merger may not be completed.
ETE intends to finance a portion of the cash component of the SUG Merger consideration with debt financing. In October 2011, ETE entered into a credit agreement with a group of lenders (the "Bridge Lenders") pursuant to which, subject to the conditions set forth therein, the Bridge Lenders have committed to provide a 364-day a bridge term loan facility (the "Bridge Term Loan Facility") in an aggregate principal amount of $3.7 billion (or such lesser amount as is equal to the lesser of (i) the amount that is sufficient to fund the total amount of cash consideration paid in the SUG Merger and (ii) the amount that ETE may elect to borrow). The commitment to provide the Bridge Term Facility is subject to various conditions, including the absence of a material adverse effect on Southern Union having occurred subsequent to December 31, 2010 and other customary closing conditions.
In the event that the financing contemplated by the Bridge Term Facility is not available to ETE, other financing may not be available to ETE on acceptable terms, in a timely manner, or at all. If other financing becomes necessary and ETE is unable to secure such additional financing, the SUG Merger may not be completed. ETE does not have a right to terminate the merger agreement in the event it does not have adequate funds to complete the transaction at closing. In the merger agreement, ETE represented to Southern Union that it would have available, at the closing of the SUG Merger, all funds required to consummate the transactions contemplated by the merger agreement. Southern Union would have a right to terminate the merger agreement if ETE breached this representation in a manner such that ETE would not be able to satisfy this representation on or before June 30, 2012, or in the event some regulatory approvals have not been achieved, December 31, 2012.
Pending litigation against ETE and Southern Union could result in the payment of damages in the event the SUG Merger is completed and/or may adversely affect the combined company’s business, financial condition or results of operations following the SUG Merger.
In connection with the SUG Merger, purported stockholders of Southern Union have filed several stockholder class action lawsuits against ETE, Southern Union, and the Southern Union Board in the District Courts of Harris County, Texas and in the Delaware Courts of Chancery. Among other remedies, the plaintiffs seek monetary damages. If a final settlement is not reached, or if a dismissal is not obtained, these lawsuits could result in substantial costs to ETE and Southern Union, including any costs associated with the indemnification of directors. Additional lawsuits may be filed against ETE and/or Southern Union related to the SUG Merger. The defense or settlement of any lawsuit or claim that remains unresolved at the time the SUG Merger is completed may adversely affect the combined company’s business, financial condition or results of operations.
If the merger agreement is terminated, Southern Union may be obligated to reimburse ETE for costs incurred related to the SUG Merger and, under certain circumstances, pay a breakup fee to ETE. Southern Union may be unable to reimburse these costs or pay any potential breakup fee to ETE.
In certain circumstances, upon termination of the merger agreement, Southern Union would be responsible for reimbursing ETE for up to $54.0 million in expenses related to the transaction and may be obligated to pay a breakup fee to ETE of $181.3 million. If the merger agreement is terminated, the expense reimbursements and the breakup fee required to be paid by Southern Union under the merger agreement may require Southern Union to seek loans or borrow amounts to enable it to pay these amounts to ETE. In either case, Southern Union may not be able to fulfill such obligations.

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Southern Union will be a corporate subsidiary of ETE after the SUG Merger and will remain subject to corporate-level income taxes.
After the SUG Merger, ETE will own and operate certain aspects of Southern Union’s business through Southern Union as a wholly owned corporate subsidiary of ETE. Accordingly, Southern Union will continue to be subject to corporate-level tax, which may reduce the cash available for distribution to ETE and, in turn, to ETE unitholders. If the IRS were to successfully assert that Southern Union has more tax liability than ETE anticipated or legislation were enacted that increased the corporate tax rate, the cash available for distribution by ETE could be further reduced.

ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

ITEM 2. PROPERTIES
A description of our properties is included in “Item 1. Business.” We share an office building for our executive office in Dallas, Texas with ETP. In addition, ETP owns office buildings in Houston and San Antonio, Texas and Regency leases two floors in an office building in Dallas, Texas. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.
We believe that we have satisfactory title to or valid rights to use all of our material properties. Although some of our properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements and immaterial encumbrances, easements and restrictions, we do not believe that any such burdens will materially interfere with our continued use of such properties in our business, taken as a whole. In addition, we believe that we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local government and regulatory authorities which relate to ownership of our properties or the operations of our business.
Substantially all of ETP’s and Regency’s pipelines, are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. ETP and Regency have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, properties on which our pipelines were built were purchased in fee. ETP also owns and operates multiple natural gas and NGL storage facilities and owns or leases processing, treating and conditioning facilities in connection with its midstream operations.

ITEM 3. LEGAL PROCEEDINGS
We are not aware of any material legal or governmental proceedings against ETE or our Operating Companies, or contemplated to be brought against ETE or our Operating Companies, under the various environmental protection statutes to which we and they are subject.
For a description of legal proceedings, see Note 10 to our consolidated financial statements.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.



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PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Parent Company
Market Price of and Distributions on Common Units and Related Unitholder Matters
The Parent Company’s common units are listed on the NYSE under the symbol “ETE.” The following table sets forth, for the periods indicated, the high and low sales prices per ETE Common Unit, as reported on the NYSE Composite Transaction Tape, and the amount of cash distributions paid per ETE Common Unit for the periods indicated.
 
 
Price Range
 
Cash
Distribution (1)
 
High
 
Low
 
Fiscal Year 2011:
 
 
 
 
 
Fourth Quarter (2)
$
42.00

 
$
30.78

 
$
0.625

Third Quarter (2)
45.42

 
33.21

 
0.625

Second Quarter (2)
47.34

 
38.77

 
0.625

First Quarter (2)
45.47

 
37.27

 
0.560

Fiscal Year 2010:
 
 
 
 
 
Fourth Quarter (2)
$
40.46

 
$
36.90

 
$
0.540

Third Quarter (2)
37.97

 
32.61

 
0.540

Second Quarter (2)
35.51

 
27.25

 
0.540

First Quarter
34.80

 
30.09

 
0.540


(1) 
Distributions are shown in the quarter with respect to which they relate. For each of the indicated quarters for which distributions have been made, an identical per unit cash distribution was paid on any units subordinated to our Common Units outstanding at such time. Please see “– Cash Distribution Policy” below for a discussion of our policy regarding the payment of distributions.
(2) 
Excludes the Series A Convertible Preferred Units issued in connection with the Regency Transactions in May 2010. See Note 7 to our consolidated financial statements.
Description of Units
As of February 1, 2012, there were approximately 86,914 individual common unitholders, which includes common units held in street name. Common units represent limited partner interest in us that entitle the holders to the rights and privileges specified in the Parent Company’s Third Amended and Restated Agreement of Limited Partnership, as amended to date (the “Partnership Agreement”).
As of December 31, 2011, common units represent an aggregate 99.69% limited partner interest in us. Our General Partner owns an aggregate 0.31% General Partner interest in us. Our common units are registered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and are listed for trading on the NYSE. Each holder of a common unit is entitled to one vote per unit on all matters presented to the limited partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all common units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our Partnership Agreement. The common units are entitled to distributions of Available Cash as described below under “– Cash Distribution Policy”.
Cash Distribution Policy
General.  The Parent Company will distribute all of its “Available Cash” to its unitholders and its General Partner within 50 days following the end of each fiscal quarter.
Definition of Available Cash.  Available Cash is defined in the Parent Company’s Partnership Agreement and generally means, with respect to any calendar quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary

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or appropriate in the reasonable discretion of the General Partner to:
provide for the proper conduct of its business;
comply with applicable law and/or debt instrument or other agreement; and
provide funds for distributions to unitholders and its General Partner in respect of any one or more of the next four quarters.
The total amount of distributions declared is reflected in Note 8 to our consolidated financial statements.
Recent Sales of Unregistered Securities
None.
Issuer Purchases of Equity Securities
None.

ITEM 6.  SELECTED FINANCIAL DATA
Currently, the Parent Company has no separate operating activities apart from those conducted by the operating subsidiaries of our consolidated investees, ETP and Regency. On May 26, 2010, we completed the Regency Transactions as described in “Item 1. Business – Overview.” We have accounted for the Regency Transactions using the purchase method of accounting. As a result, we commenced consolidating the results of Regency and its consolidated subsidiaries on May 26, 2010.
In November 2007, we changed our fiscal year end from August 31 to December 31 and, in connection with such change, we have reported financial results for a four-month transition period ended December 31, 2007.
The selected historical financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and accompanying notes thereto included elsewhere in this report. The amounts in the table below, except per unit data, are in thousands.
 
 
Years Ended December 31,
 
Four Months Ended
December 31, 2007
 
Year Ended
August 31, 2007
Statement of Operations Data:
2011
 
2010
 
2009
 
2008
 
Total revenues
$
8,240,703

 
$
6,598,132

 
$
5,417,295

 
$
9,293,367

 
$
2,349,342

 
$
6,792,037

Operating income
1,234,819

 
1,036,729

 
1,110,398

 
1,098,903

 
316,651

 
809,336

Income from continuing operations
528,247

 
337,824

 
697,871

 
679,754

 
182,809

 
551,968

Basic net income per limited partner unit
1.39

 
0.86

 
1.98

 
1.68

 
0.41

 
1.56

Diluted net income per limited partner unit
1.38

 
0.86

 
1.98

 
1.68

 
0.41

 
1.55

Cash distribution per unit
2.44

 
2.16

 
2.14

 
1.91

 
0.55

 
1.46

Balance Sheet Data (at period end):
 
 
 
 
 
 
 
 
 
 
 
Total assets
20,896,793

 
17,378,730

 
12,160,509

 
11,069,902

 
9,462,094

 
8,183,089

Long-term debt, less current maturities
10,946,864

 
9,346,067

 
7,750,998

 
7,190,357

 
5,870,106

 
5,198,676

Total equity
7,388,945

 
6,247,732

 
3,220,251

 
2,339,316

 
2,091,156

 
1,835,300

 

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Energy Transfer Equity, L.P. is a Delaware limited partnership whose common units are publicly traded on the NYSE under the ticker symbol “ETE.” ETE was formed in September 2002 and completed its initial public offering in February 2006.
The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included in “Item 8. Financial Statements and Supplementary Data” of this report. This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Item 1A. Risk Factors” of this report.
Unless the context requires otherwise, references to “we,” “us,” “our,” and “ETE” shall mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. (“ETP”), Energy Transfer Partners G.P., L.P. (“ETP GP”), the General Partner of ETP, ETP GP’s General Partner, Energy Transfer Partners, L.L.C. (“ETP LLC”), Regency Energy Partners LP (“Regency”), Regency GP LP (“Regency GP”), the general partner of Regency, and Regency GP’s General Partner, Regency GP LLC (“Regency LLC”). References to “the Parent Company” shall mean Energy Transfer Equity, L.P. on a stand-alone basis.
OVERVIEW
Energy Transfer Equity, L.P. directly and indirectly owns equity interests in ETP and Regency, both publicly traded master limited partnerships engaged in diversified energy-related services.
At December 31, 2011, our equity interests consisted of:
 
 
General Partner
Interest (as a %
of total
partnership
interest)
 
Incentive
Distribution
Rights
(“IDRs”)
 
Limited
Partner Units
ETP
1.5
%
 
100
%
 
50,226,967

Regency
1.8
%
 
100
%
 
26,266,791

The principal sources of the Parent Company's cash flow are distributions it receives from its direct and indirect investments in limited and general partner interests in ETP and Regency. The Parent Company’s primary cash requirements are for distributions to its partners and holders of the Series A Convertible Preferred Units (the “Preferred Units”), general and administrative expenses, debt service requirements and at ETE's election, capital contributions to ETP and Regency in respect of ETE's general partner interest in ETP and Regency. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of ETE's subsidiaries.
We acquired our equity interests in Regency in a series of transactions, which we refer to as the “Regency Transactions,” that were completed on May 26, 2010. In the Regency Transactions, we:
acquired the general partner interest and IDRs in Regency in exchange for 3,000,000 Preferred Units having an aggregate liquidation preference of $300 million;
acquired from ETP an indirect 49.9% interest in Midcontinent Express Pipeline LLC (“MEP”), ETP’s joint venture with Kinder Morgan Energy Partners, L.P. (“KMP”) to operate the Midcontinent Express Pipeline, and an option to acquire an additional 0.1% interest in MEP in exchange for the redemption by ETP of approximately 12.3 million ETP Common Units we previously owned; and
acquired 26.3 million Regency Common Units in exchange for our contribution of all of our interests in MEP, including the option to acquire an additional 0.1% interest, to Regency.
In order to fully understand the financial condition and results of operations of the Parent Company on a stand-alone basis, we have included discussions of Parent Company matters apart from those of our consolidated group.
General
Our primary objective is to increase the level of our distributable cash flow to our unitholders over time by pursuing a business strategy that is currently focused on growing our subsidiaries’ natural gas and NGL businesses through, among other things,

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pursuing certain construction and expansion opportunities relating to our subsidiaries’ existing infrastructure and acquiring certain strategic operations and businesses or assets. The actual amounts of cash that we will have available for distribution will primarily depend on the amount of cash our subsidiaries generate from their operations.
Our principal operations include the following reportable segments:
Investment in ETP – ETP is a publicly traded partnership owning and operating a diversified portfolio of energy assets. ETP has pipeline operations in Arizona, Arkansas, Colorado, Louisiana, New Mexico, Utah and West Virginia and owns the largest intrastate pipeline system in Texas. ETP currently has natural gas operations that include more than 17,500 miles of gathering and transportation pipelines, treating and processing assets, and three storage facilities located in Texas. ETP also holds a 70% membership interest in Lone Star NGL LLC (“Lone Star”), a joint venture that owns and operates NGL storage, fractionation and transportation assets in Texas, Louisiana and Mississippi.
Investment in Regency – Regency is a publicly traded partnership engaged in the gathering and processing, contract compression, treating and transportation of natural gas and the transportation, fractionation and storage of NGLs. Regency focuses on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Bone Spring and Avalon shales, as well as the Permian Delaware basin. Its assets are primarily located in Texas, Louisiana, Arkansas, Pennsylvania, California, Mississippi, Alabama, West Virginia and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% membership interest in Lone Star.
Each of the respective general partners of ETP and Regency have separate operating management and boards of directors. We control ETP and Regency through our ownership of their respective general partners. See further discussion of ETP and Regency’s operations in Note 1 to our consolidated financial statements.
Recent Developments
Pending Acquisition
On July 19, 2011, we entered into a transaction to acquire Southern Union Company, a Delaware corporation (“SUG”). This transaction, which we refer to as the SUG Merger, will provide us with direct ownership of assets that are complementary to the assets owned and operated by ETP and Regency. To execute the SUG Merger, we entered into a Second Amended and Restated Plan of Merger (the “SUG Merger Agreement”) with Sigma Acquisition Corporation, a Delaware corporation and our wholly-owned subsidiary (“Merger Sub”), and SUG. The Second Amended Merger Agreement modifies certain terms of the Amended and Restated Agreement and Plan of Merger entered into by us, Merger Sub and SUG on July 4, 2011. Under the terms of the SUG Merger Agreement, Merger Sub will merge with and into SUG, with SUG continuing as the surviving entity and becoming our wholly-owned subsidiary subject to certain conditions to close. Pursuant to the SUG Merger Agreement, we will acquire all of the outstanding shares of SUG in a transaction valued at $9.4 billion, including $5.7 billion in cash and ETE Common Units and $3.7 billion of existing SUG indebtedness. Stockholders of SUG may elect to exchange each share of SUG stock for either $44.25 in cash or 1.00 ETE Common Unit. The maximum cash component is 60% of the aggregate consideration and the common unit component can fluctuate between 40% and 50%. Elections in excess of either the cash or common unit limits will be subject to proration.
As described in more detail below under the caption “Liquidity and Capital Resources — Overview — Parent Company Only,” we have secured $3.7 billion in committed financing from the Bridge Loan Lenders to fund a portion of the cash consideration related to the SUG Merger, which is expected to be replaced by permanent financing with the syndication of a new senior secured credit facility of up to $2.3 billion, and completion of the Citrus Acquisition. On December 9, 2011, the special meeting of the SUG stockholders was held and the SUG stockholders voted to approve the SUG Merger. We and SUG have made filings with the Missouri Public Service Commission and expect to receive its approval of the SUG Merger in the first quarter of 2012. Closing of this business combination is contingent upon several conditions, including regulatory approvals, and we expect the transaction to close in the first quarter of 2012.
On July 19, 2011, ETP entered into an Amended Citrus Merger Agreement pursuant to which it is anticipated that SUG will cause the contribution to ETP of SUG’s 50% interest in Citrus Corp., which owns 100% of the Florida Gas Transmission (“FGT”) pipeline system, in exchange for approximately $1.895 billion in cash and $105 million of ETP Common Units, contemporaneous with the completion of the merger between SUG and us pursuant to the SUG Merger Agreement as described in Note 3 to our consolidated financial statements.
We expect to incur additional general and administrative costs in connection with consummation of this merger.

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Propane Operations
On January 12, 2012, ETP contributed its propane operations, consisting of Heritage Operating, L.P. (“HOLP”) and Titan Energy Partners, L.P. (“Titan”) (collectively, the “Propane Business”), to AmeriGas Partners, L.P. (“AmeriGas”). ETP received $1.46 billion in cash and approximately 29.6 million AmeriGas common units in consideration for the contribution of the Propane Business. AmeriGas also assumed of approximately $71 million of existing HOLP debt.
ETP's 2012 Financing Transactions
In January 2012, ETP issued $2.0 billion principal amount of Senior Notes, the proceeds from which it anticipates using to fund the cash potion of the Citrus Acquisition and for general partnership purposes. In January and February 2012, ETP also completed the repurchase of approximately $750 million of its Senior Notes.
Ranch Joint Venture
On December 2, 2011, Ranch Westex JV LLC (“Ranch JV”) was formed by Regency, Anadarko Pecos Midstream LLC and Chesapeake West Texas Processing, L.L.C., each owning 33.33% of the joint venture. Ranch JV, upon completion of construction in 2012, will process natural gas delivered from the NGL-rich Bone Springs and Avalon shale formations in West Texas. The project consists of two plants, a 25 MMcf/d refrigeration plant and a 100 MMcf/d cryogenic processing plant. The initial start-up of the refrigeration unit is expected to be in service by the second quarter of 2012, with full facilities available by the fourth quarter of 2012.
Trends and Outlook
We expect to close the SUG Merger in the near term, and we expect that the merger will:
provide accretion to cash flow, both immediately and over the long-term;
provide a commercial and operational fit with the existing natural gas and NGL operations that we control through ETP and Regency;
create a larger interstate and midstream platform with enhanced and expanded geographic diversity;
add significant demand-side, market-centric pipelines to the asset portfolio that we control and provide additional organic growth opportunities in strategic geographical locations as well as potential affiliate joint ventures;
increase our fee-based revenues from long-term contracts with strong credit quality customers;
allow us and our subsidiaries to take advantage of immediate operational and commercial synergies;
diversify our cash flow, as the combined entities will derive a larger portion of cash flow from large scale, regulated and investment-grade operations; and,
provide the potential for asset drop-downs to ETP and Regency or asset sales over time.
In addition, we expect to benefit from continued organic growth and acquisitions among our existing consolidated subsidiaries. ETP, Regency and Lone Star's aggregate growth capital expenditures for 2011 were $1.8 billion. In 2012, ETP, Regency and Lone Star expect their aggregate capital expenditures to be between $2.6 billion and $2.9 billion, which includes additional NGL assets including construction of a NGL fractionator at Mont Belvieu, assets in in the Eagle Ford Shale, assets in the Woodford and Barnett Shales, in addition to various other growth projects. In addition to these capital expenditures, ETP expects to complete its acquisition of a 50% interest in Citrus Corp. in conjunction with our acquisition of SUG, as described above. Along with the inherent benefits of greater scale and cash flow diversification that we experience from growth and acquisitions that occur at ETP and Regency, we also expect to directly benefit through increases in the distributions that we receive through our limited partner, general partner and IDR interests in ETP and Regency.

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Results of Operations
Year Ended December 31, 2011 Compared to the Year Ended December 31, 2010 (tabular dollar amounts are expressed in thousands)
Consolidated Results
 
 
Years Ended December 31,
 
Change
 
2011
 
2010
 
Revenues
$
8,240,703

 
$
6,598,132

 
$
1,642,571

Cost of products sold
5,182,999

 
4,111,337

 
1,071,662

Gross margin
3,057,704

 
2,486,795

 
570,909

Operating expenses
918,918

 
784,546

 
134,372

Depreciation and amortization
611,809

 
431,199

 
180,610

Selling, general and administrative
292,158

 
234,321

 
57,837

Operating income
1,234,819

 
1,036,729

 
198,090

Interest expense, net of interest capitalized
(739,811
)
 
(624,887
)
 
(114,924
)
Equity in earnings of affiliates
117,188

 
65,220

 
51,968

Losses on disposal of assets
(816
)
 
(5,255
)
 
4,439

Losses on non-hedged interest rate derivatives
(77,806
)
 
(52,357
)
 
(25,449
)
Allowance for equity funds used during construction
957

 
28,942

 
(27,985
)
Impairment of investments in affiliates
(5,355
)
 
(52,620
)
 
47,265

Other, net
15,954

 
(44,210
)
 
60,164

Income tax expense
(16,883
)
 
(13,738
)
 
(3,145
)
Loss from discontinued operations

 
(1,244
)
 
1,244

Net income
$
528,247

 
$
336,580

 
$
191,667


The discussion under “Parent Company Results” below analyzes the results of operations of the Parent Company on a stand alone basis for the periods presented, and the discussion under “Segment Operating Results” below analyzes the results of operations related to our reportable segments.
Parent Company Results
The Parent Company currently has no separate operating activities apart from those conducted by the operating subsidiaries of ETP and Regency and its principal sources of cash flow are from its direct and indirect investments in the limited and general partner interests of ETP and Regency.
The following table presents the results of the stand-alone results of operations of the Parent Company for the periods indicated:
 
 
Years Ended December 31,
 
Change
 
2011
 
2010
 
Selling, general and administrative expenses
$
(29,641
)
 
$
(21,829
)
 
$
(7,812
)
Interest expense
(163,612
)
 
(167,658
)
 
4,046

Equity in earnings of affiliates
509,361

 
455,901

 
53,460

Losses on non-hedged interest rate derivatives

 
(53,388
)
 
53,388

Other, net
(5,796
)
 
(19,721
)
 
13,925

Selling, General and Administrative Expenses.  Selling, general and administrative expenses increased principally due to an increase in acquisition-related costs associated with the SUG Merger. Acquisition-related costs of $21.4 million were incurred in 2011 in relation to the SUG Merger compared to $12.8 million of acquisition-related costs associated with the Regency Transaction in 2010.

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Interest Expense.  Interest expense decreased primarily due to the recognition of $66.4 million of realized losses on hedged interest rate swaps in September 2010 in connection with the refinancing of indebtedness that would have come due in 2011 and 2012. These realized losses were offset by an increase in interest expense that primarily resulted from the Parent Company's issuance of $1.8 billion of aggregate principal amount of 7.5% senior notes in September 2010.
In addition, interest expense for the periods presented reflected distributions on the Preferred Units issued by ETE in connection with the acquisition of a controlling interest in Regency in May 2010. Distributions on Preferred Units were $24 million and $14.4 million for the years ended December 31, 2011 and 2010, respectively.
Equity in Earnings of Affiliates.  Equity in earnings of affiliates represents earnings of the Parent Company related to its investments in ETP and Regency. The Parent Company recorded equity in earnings of ETP of $490.3 million and $455.3 million for the years ended December 31, 2011 and 2010, respectively. An analysis of ETP's operating results is included in “Segment Operating Results” below. The Parent Company recorded equity in earnings of Regency of $19.1 million and $0.6 million for the years ended December 31, 2011 and 2010, respectively. Equity in earnings of Regency for 2010 represents only the period subsequent to the Parent Company's acquisition of a controlling interest in Regency in May 2010.
Losses on Non-Hedged Interest Rate Derivatives.  In September 2010, the Parent Company terminated its interest swaps that were not accounted for as hedges in connection with its issuance of $1.8 billion of senior notes. Prior to that settlement, changes in the fair value of and cash payments related to these swaps were recorded directly in earnings.
Other, net.  Other expenses decreased primarily due to a decrease between periods related to non-cash charges recorded to increase the carrying value of the ETE Preferred Units that were issued by the Parent Company in connection with the acquisition of a controlling interest in Regency in May 2010. The year ended December 31, 2010 included a non-cash charge of $12.7 million and the year ended December 31, 2011 included a non-cash charge of $5.3 million to increase the carrying value of the ETE Preferred Units.
Segment Operating Results
We have two reportable segments, which conduct their business exclusively in the United States of America, as follows:
Investment in ETP — Reflects the consolidated operations of ETP.
Investment in Regency — Reflects the consolidated operations of Regency.
We evaluate the performance of our operating segments based on net income. The following tables present the financial information by segment. The amounts reflected as “Corporate and Other” include the Parent Company activity and the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
For additional information regarding our business segments, see “Item 1. Business” of this report and Notes 1 and 14 to our consolidated financial statements.
Net income by segment is as follows:
 
 
Years Ended December 31,
 
 
 
2011
 
2010
 
Change
Investment in ETP
$
697,162

 
$
617,222

 
$
79,940

Investment in Regency
73,619

 
(5,972
)
 
79,591

Corporate and Other
(214,346
)
 
(274,670
)
 
60,324

Adjustments and Eliminations
(28,188
)
 

 
(28,188
)
Net income
$
528,247

 
$
336,580

 
$
191,667


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Investment in ETP
 
 
Years Ended December 31,
 
Change
 
2011
 
2010
 
Revenues
$
6,850,440

 
$
5,884,827

 
$
965,613

Cost of products sold
4,189,353

 
3,599,941

 
589,412

Gross margin
2,661,087

 
2,284,886

 
376,201

Operating expenses
773,767

 
707,271

 
66,496

Depreciation and amortization
430,904

 
343,011

 
87,893

Selling, general and administrative
211,609

 
176,433

 
35,176

Operating income
1,244,807

 
1,058,171

 
186,636

Interest expense, net of interest capitalized
(474,113
)
 
(412,553
)
 
(61,560
)
Equity in earnings of affiliates
25,836

 
11,727

 
14,109

Losses on disposal of assets
(3,188
)
 
(5,043
)
 
1,855

Gains (losses) on non-hedged interest rate derivatives
(77,409
)
 
4,616

 
(82,025
)
Allowance for equity funds used during construction
957

 
28,942

 
(27,985
)
Impairment of investments in affiliates
(5,355
)
 
(52,620
)
 
47,265

Other, net
4,442

 
(482
)
 
4,924

Income tax expense
(18,815
)
 
(15,536
)
 
(3,279
)
Net income
$
697,162

 
$
617,222

 
$
79,940

Gross Margin.  For the year ended December 31, 2011 compared to the year ended December 31, 2010, ETP’s gross margin increased primarily due to the net impacts of the following:
Revenue generated by ETP's interstate transportation operations increased $154.3 million primarily as a result of incremental revenues from the Tiger pipeline being placed into service in December 2010 and a related expansion placed into service in August 2011. Increased revenue from the Tiger pipeline was partially offset by decreased revenue from the Transwestern pipeline as a result of lower volumes.
Gross margin from ETP's midstream operations increased $97.2 million, $44.7 million of which was a result from increases in gathering and processing fee-based revenues primarily due to increased volumes in production in the Eagle Ford Shale along with increased volumes in ETP's assets in West Virginia and North Texas. Gross margin for non fee-based contracts and processing increased $48.7 million primarily due to more favorable NGL prices.
Gross margin from ETP's NGL transportation and services operations was $178.8 million during 2011, which represented 100% of the results from Lone Star since LDH Energy Asset Holdings LLC ("LDH") was acquired in May 2011. Accordingly, no comparative amounts were reflected in ETP's results prior to May 2, 2011.
Gross margin from ETP's retail propane and other retail propane related operations decreased $37.1 million primarily as a result of decreased volumes which were affected by unfavorable weather patterns and continued customer conservatism.
Operating Expenses.  Operating expenses increased during 2011 compared to 2010 primarily due to operating expenses of $39.4 million for Lone Star, which acquired LDH in May 2011 and was not reflected in prior period. In addition, operating expenses for ETP's midstream operations increased $17.7 million as a result of increased maintenance and operating expenses and employee expenses due to higher volumes and assets on its systems and processing/treating facilities. The completion of the Tiger pipeline and its related expansion also attributed to increases in operating expenses.
Depreciation and Amortization. Depreciation and amortization increased due to acquisitions and assets placed in service since 2010. Depreciation and amortization increased by $28.3 million for ETP’s interstate transportation operations primarily due to the Tiger pipeline which was placed in service in December 2010. Depreciation and amortization increased by $25.3 million for ETP’s midstream operations primarily due to incremental depreciation from the continued expansion of its Northern Louisiana and Southeast Texas assets. Depreciation and amortization for ETP’s NGL transportation and services operations was $32.5 million from its inception in May 2011 through December 31, 2011.

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Selling, General and Administrative Expense.  Selling, general and administrative expenses increased partially due to selling, general and administrative expenses of $13.3 million for Lone Star, which was acquired in May 2011 and not reflected in the prior period. In addition, selling, general and administrative expenses for ETP's interstate operations increased $13.9 million primarily due to increased allocated and employee-related expenses, including incremental amounts related to the Tiger pipeline.
Interest Expense. Interest expense increased primarily due to ETP's issuance of $1.5 billion of senior notes in May 2011, the proceeds from which were used to repay borrowings on its revolving credit facility, to fund growth projects and for general partnership purposes.
Gains (Losses) on Non-Hedged Interest Rate Derivatives. The year ended December 31, 2011 reflected losses on non-hedged interest rate swaps for which ETP had total notional amounts outstanding of $1.65 billion as of December 31, 2011, which included $1.15 billion of forward-starting floating-to-fixed swaps used to hedge interest rates associated with anticipated note issuances and $500 million of fixed-to-floating swaps used to swap a portion of ETP's fixed rate debt to floating. During the second half of 2011, forward rates decreased significantly due to global economic uncertainty which resulted in unrealized non-cash losses on ETP's forward-starting floating-to-fixed swaps.
Allowance for Equity Funds Used During Construction. Allowance for equity funds used during construction for 2011 reflected amounts recorded in connection with the expansion of the Tiger pipeline which was completed in August 2011, whereas 2010 reflected amounts recorded in connection with the original construction of the Tiger pipeline.
Impairment of Investments in Affiliates. For 2011, ETP's results reflected a non-cash charge to write off all of its investment in a joint venture for which projects are no longer being pursued. During 2010, in conjunction with the transfer of its interest in Midcontinent Express Pipeline LLC ("MEP") in May 2010, ETP recorded a non-cash charge of approximately $52.6 million to reduce the carrying value of its interest in MEP to its estimated fair value.
Income Tax Expense. The increase in income tax expense between the periods was primarily due to increases in taxable income within ETP's subsidiaries that are taxable corporations, in addition to an increase in amounts recorded for the Texas margins tax resulting from increased operating income.
Investment in Regency
 
 
Years Ended December 31,
 
 
 
2011
 
2010
 
Change
Revenues
$
1,433,898

 
$
716,613

 
$
717,285

Cost of products sold
1,012,826

 
504,327

 
508,499

Gross margin
421,072

 
212,286

 
208,786

Operating expenses
147,643

 
77,808

 
69,835

Depreciation and amortization
168,684

 
75,967

 
92,717

Selling, general and administrative
67,408

 
43,739

 
23,669

Gains (losses) on disposal of assets
(2,372
)
 
213

 
(2,585
)
Operating income
39,709

 
14,559

 
25,150

Interest expense, net of interest capitalized
(102,474
)
 
(48,251
)
 
(54,223
)
Equity in earnings of affiliates
119,540

 
53,493

 
66,047

Other, net
17,309

 
(23,977
)
 
41,286

Income tax expense
(465
)
 
(552
)
 
87

Loss from discontinued operations

 
(1,244
)
 
1,244

Net income
$
73,619

 
$
(5,972
)
 
$
79,591

ETE obtained control of Regency on May 26, 2010. Changes between the year ended December 31, 2011 and the period from May 26, 2010 to December 31, 2010 were primarily due to the consolidation of Regency beginning May 26, 2010.

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Year Ended December 31, 2010 Compared to the Year Ended December 31, 2009 (tabular dollar amounts are expressed in thousands)
Consolidated Results
 
 
Years Ended December 31,
 
Change
 
2010
 
2009
 
Revenues
$
6,598,132

 
$
5,417,295

 
$
1,180,837

Cost of products sold
4,111,337

 
3,122,056

 
989,281

Gross margin
2,486,795

 
2,295,239

 
191,556

Operating expenses
784,546

 
680,893

 
103,653

Depreciation and amortization
431,199

 
325,024

 
106,175

Selling, general and administrative
234,321

 
178,924

 
55,397

Operating income
1,036,729

 
1,110,398

 
(73,669
)
Interest expense, net of interest capitalized
(624,887
)
 
(468,420
)
 
(156,467
)
Equity in earnings of affiliates
65,220

 
20,597

 
44,623

Losses on disposal of assets
(5,255
)
 
(1,564
)
 
(3,691
)
Gains (losses) on non-hedged interest rate derivatives
(52,357
)
 
33,619

 
(85,976
)
Allowance for equity funds used during construction
28,942

 
10,557

 
18,385

Impairment of investment in affiliate
(52,620
)
 

 
(52,620
)
Other, net
(44,210
)
 
1,913

 
(46,123
)
Income tax expense
(13,738
)
 
(9,229
)
 
(4,509
)
Loss from discontinued operations
(1,244
)
 

 
(1,244
)
Net income
$
336,580

 
$
697,871

 
$
(361,291
)

Parent Company Results
The following table presents the results of the stand-alone results of operations of the Parent Company for the periods indicated:
 
 
Years Ended December 31,
 
Change
 
2010
 
2009
 
Selling, general and administrative expenses
$
(21,829
)
 
$
(4,970
)
 
$
(16,859
)
Interest expense
(167,658
)
 
(74,049
)
 
(93,609
)
Equity in earnings of affiliates
455,901

 
526,383

 
(70,482
)
Losses on non-hedged interest rate derivatives
(53,388
)
 
(5,620
)
 
(47,768
)
Other, net
(19,721
)
 
79

 
(19,800
)
Selling, General and Administrative Expenses.  Selling, general and administrative expenses increased principally due to $12.8 million in acquisition-related costs associated with the Regency Transactions.
Interest Expense.  Interest expense was primarily impacted by the recognition of $66.4 million of realized losses on hedged interest rate swaps that were terminated with the proceeds from the Parent Company’s September 2010 senior notes offering. In addition to the $66.4 million of realized losses on hedged interest rate swaps, the Parent Company also paid $102.2 million to terminate non-hedged interest rate swaps. The $102.2 million of realized losses on non-hedged interest rate swaps had previously been recognized in net income and therefore the termination of the non-hedged swaps did not impact earnings. The total cash paid to terminate interest rate swaps was $168.6 million, including realized losses on hedged and non-hedged swaps.
Prior to termination of the swaps, the unrealized loss had been reflected in accumulated other comprehensive income. In addition to the realized loss from swap terminations, interest expense is also higher due to distributions on the Preferred Units issued in May 2010. For the year ended December 31, 2010, interest expense includes distributions on the ETE Preferred Units of $14.4 million.

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The remainder of the increase in Parent Company interest expense was primarily due to the issuance of senior notes in September 2010, which senior notes bore interest at a higher rate than the previous revolving credit facility and term loan facility.
Equity in Earnings of Affiliates.  Equity in earnings of affiliates decreased from 2009 to 2010 primarily due to a decrease in ETP’s net income, as discussed below under “Segment Operating Results — Investment in ETP.”
Losses on Non-Hedged Interest Rate Derivatives.  The Parent Company terminated its interest swaps that were not accounted for as hedges in September 2010 in connection with our issuance of $1.8 billion of senior notes. Prior to that settlement, changes in the fair value of and cash payments related to these swaps were recorded directly in earnings. The variable portion of these swaps was based on the three month LIBOR and its corresponding forward curve. Increases in losses on non-hedged interest rate derivatives were due to changes in these rates. The Parent Company recorded unrealized losses on its interest rate swaps as a result of decreases in the relevant floating index rates during the periods presented.
Other, net.  Other expenses increased primarily due to the non-cash charge of $12.7 million recorded to increase the carrying value of the Series A Convertible Preferred Units.
Segment Operating Results
Net income by segment was as follows:
 
 
Years Ended December 31,
 
 
 
2010
 
2009
 
Change
Investment in ETP
$
617,222

 
$
791,542

 
$
(174,320
)
Investment in Regency
(5,972
)
 

 
(5,972
)
Corporate and Other
(274,670
)
 
(93,671
)
 
(180,999
)
Net income
$
336,580

 
$
697,871

 
$
(361,291
)

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Investment in ETP
 
 
Years Ended December 31,
 
Change
 
2010
 
2009
 
Revenues
$
5,884,827

 
$
5,417,295

 
$
467,532

Cost of products sold
3,599,941

 
3,122,056

 
477,885

Gross margin
2,284,886

 
2,295,239

 
(10,353
)
Operating expenses
707,271

 
680,893

 
26,378

Depreciation and amortization
343,011

 
312,803

 
30,208

Selling, general and administrative
176,433

 
173,936

 
2,497

Operating income
1,058,171

 
1,127,607

 
(69,436
)
Interest expense, net of interest capitalized
(412,553
)
 
(394,274
)
 
(18,279
)
Equity in earnings of affiliates
11,727

 
20,597

 
(8,870
)
Losses on disposal of assets
(5,043
)
 
(1,564
)
 
(3,479
)
Gains on non-hedged interest rate derivatives
4,616

 
39,239

 
(34,623
)
Allowance for equity funds used during construction
28,942

 
10,557

 
18,385

Impairment of investment in affiliate
(52,620
)
 

 
(52,620
)
Other, net
(482
)
 
2,157

 
(2,639
)
Income tax expense
(15,536
)
 
(12,777
)
 
(2,759
)
Net income
$
617,222

 
$
791,542

 
$
(174,320
)
Gross Margin.  ETP’s gross margin decreased primarily due to the net impacts of the following:
Gross margin related to ETP’s intrastate transportation and storage operations decreased $88.7 million due to (i) a decrease of $44.6 million in transportation fees primarily cause by a decrease in the average spot price differential between West and East Texas market hubs and (ii) a decrease of $68.0 million in storage margin caused by the spread between spot prices and forward prices of natural gas being less favorable in 2010 as compared to 2009. These decreases were partially offset by an increase of $18.1 million in margin from natural gas sales and other activity primarily due to more favorable margins on gas sales and favorable impacts from system optimization activities.
Revenues from ETP’s interstate transportation operations increased by $22.2 million primarily due to increased gas prices for operational gas sales related for the Transwestern pipeline. In addition, transportation revenues increased approximately $1.9 million due to incremental revenues of $10.2 million for the Tiger pipeline since being placed into service in December 2010.
Gross margin related to ETP’s midstream operations increased $85.3 million primarily due to (i) an increase of $24.1 million in fee-based gathering and processing revenues on ETP’s North Texas system, (ii) an increase of $27.9 million in gathering and processing revenues related to increased volumes resulting from ETP’s recent acquisitions and other growth capital expenditures located in Louisiana and West Virginia, and (iii) an increase of $63.0 million in non-fee based margin primarily due to higher processing margins and more favorable NGL prices. These increases in gross margin from ETP’s midstream operations were partially offset by a decrease of $34.2 million due to losses from marketing activities as a result of less favorable market conditions.
Gross margin related to ETP’s retail propane and other retail propane related operations decreased due to (i) a decrease of $48.7 million attributable to mark-to-market adjustments for financial instruments used in commodity risk management activities, and (ii) a decrease of approximately $13.5 million due to lower sales volumes as a result of the timing and geographic distribution of temperature patterns. These unfavorable impacts to ETP’s retail propane gross margin were partially offset by an increase in the average margin per gallon sold which resulted in a favorable impact of $8.6 million between periods.
Operating Expenses.  ETP’s operating expenses increased primarily due to an increase of approximately $13.3 million in maintenance expense and an increase of approximately $12.4 million in ad valorem and other taxes resulting from increased property values and additions.
Depreciation and Amortization.  ETP’s depreciation and amortization expense increased due to acquisitions and continued expansion of existing assets.

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Selling, General and Administrative Expense.  ETP’s selling, general and administrative expenses increased primarily due to increased employee-related costs which were significantly offset by a decrease of approximately $31.3 million in professional fees.
Interest Expense.  Interest expense increased principally due to ETP’s issuance of $1.0 billion of senior notes in April 2009 and Transwestern’s issuance of $350.0 million of senior notes in December 2009, a portion of the proceeds of which were used to repay borrowings that had been accruing interest at a lower rate.
Equity in Earnings of Affiliates.  Equity in earnings of affiliates decreased primarily due to ETP’s transfer of substantially all of our interest in MEP to ETE on May 26, 2010. The impact of the MEP transfer was offset by increased earnings from MEP during the period prior to May 26, 2010 as a result of placing the Midcontinent Express pipeline into service in 2009.
Losses on Disposal of Assets.  The increase in losses from the disposal of assets in 2010 primarily resulted from the retirement of pad gas from ETP’s Bammel Storage Facility.
Gains on Non-Hedged Interest Rate Derivatives.  The gains on non-hedged interest rate swaps in 2009 resulted from an increase in the index rate during the periods presented prior to settlement. The gains on non-hedged interest rate derivatives in 2010 reflect the gains recognized on swaps entered into during the period.
Allowance for Equity Funds Used During Construction.  Allowance for equity funds used during construction (“AFUDC”) increased during 2010 primarily due to construction on the Tiger pipeline which was placed in service in December 2010.
Impairment of Investment in Affiliate.  In conjunction with the transfer of ETP’s interest in MEP as discussed above, ETP recorded a non-cash charge of approximately $52.6 million in May 2010 to reduce the carrying value of its interest in MEP to its estimated fair value.
Investment in Regency
 
 
Years Ended December 31,
 
 
 
2010
 
2009
 
Change
Revenues
$
716,613

 
$

 
$
716,613

Cost of products sold
504,327

 

 
504,327

Gross margin
212,286

 

 
212,286

Operating expenses
77,808

 

 
77,808

Depreciation and amortization
75,967

 

 
75,967

Selling, general and administrative
43,739

 

 
43,739

Loss on disposal of assets
213

 

 
213

Operating income
14,559

 

 
14,559

Interest expense, net of interest capitalized
(48,251
)
 

 
(48,251
)
Equity in earnings of affiliates
53,493

 

 
53,493

Other, net
(23,977
)
 

 
(23,977
)
Income tax expense
(552
)
 

 
(552
)
Loss from discontinued operations
(1,244
)
 

 
(1,244
)
Net income
$
(5,972
)
 
$

 
$
(5,972
)
Amounts reflected above for the year ended December 31, 2010 represent the results of operations for Regency from May 26, 2010, the date ETE obtained control of Regency, through December 31, 2010. Changes between periods are due to the consolidation of Regency beginning May 26, 2010.
Regency adjusted its assets and liabilities to fair value as of May 26, 2010; therefore, the depreciation and amortization reflected above was based on the new basis of Regency’s assets.
Regency’s results included its equity in earnings related to its 49.9% interest in MEP from May 26, 2010 through December 31, 2010.
Regency’s results for the period from May 26, 2010 through December 31, 2010 reflected a net loss on debt refinancing of approximately $15.7 million, included in other expenses above, related to its redemption of $357.5 million 8.375% senior notes

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in October 2010. Regency issued $600 million of 6.875% senior notes and used the proceeds to redeem all of its $357.5 million 8.375% senior notes as well as to repay a portion of the outstanding borrowings on its revolving credit facility. The net impact of these borrowings and repayments also resulted in a slight increase in interest expense recognized within the period.

LIQUIDITY AND CAPITAL RESOURCES
Overview
Parent Company Only
The principal sources of the Parent Company's cash flow are distributions it receives from its direct and indirect investments in limited and general partner interests in ETP and Regency. The amount of cash that ETP and Regency distribute to their respective partners, including the Parent Company, each quarter is based on earnings from their respective business activities and the amount of available cash, as discussed below.
The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements, distributions to its partners and holders of the Preferred Units and at ETE’s election, capital contributions to ETP and Regency in respect of ETE’s general partner interests in ETP and Regency. The Parent Company currently expects to fund its short-term needs for such items with its distributions from ETP and Regency. The Parent Company distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its Unitholders on a quarterly basis.
On July 19, 2011, ETE entered into the SUG Merger Agreement. Under the terms of the SUG Merger Agreement, ETE will acquire all of the outstanding shares of SUG in a transaction valued at $9.4 billion at the time of the execution of the SUG Merger Agreement, including $5.7 billion in cash and ETE Common Units and $3.7 billion of existing SUG indebtedness. Pursuant to the SUG Merger Agreement, stockholders of SUG may elect to exchange each share of SUG stock for either $44.25 in cash or 1.00 ETE Common Unit. The maximum cash component is 60% of the aggregate consideration and the common unit component can fluctuate between 40% and 50%. Elections in excess of either the cash or common unit limits will be subject to proration.
ETE intends to finance a portion of the cash component of the SUG Merger consideration with debt financing. In connection with entering into the merger agreement, ETE has entered into a senior bridge term loan credit agreement (the "Bridge Loan Agreement") with the Bridge Lenders, pursuant to which, subject to the conditions set forth therein, the Bridge Lenders have agreed to provide a 364-day Bridge Term Loan Facility in an aggregate principal amount of $3.7 billion. ETE's ability to borrow under the Bridge Loan Agreement is subject to the satisfaction of certain conditions precedent, including the absence of a material adverse affect on SUG having occurred subsequent to December 31, 2010 and the delivery of certain documents requested by the administrative agent (such as financial statements, favorable opinions of counsel and customary corporate authorization documents) and the payment of relevant fees and expenses. ETE may use the proceeds of the loans under the Bridge Loan Agreement to finance the SUG Merger, to repay its remaining indebtedness under the Parent Company Credit Agreement (to the extent repaid on the date of initial borrowing under the Bridge Loan Agreement) and to pay transaction costs related to the consummation of the SUG Merger and the Bridge Loan Agreement.
We intend to pursue other financing sources, including a senior note offering or term loan; however, there is no assurance that such financing will be obtained or at terms more favorable than the Bridger Loan Agreement.
In February 2012, we launched the syndication of a new senior secured credit facility of up to $2.3 billion. We intend to use the net proceeds from the senior secured credit facility, along with proceeds received from ETP in the Citrus Acquisition, to fund the cash portion of the SUG Merger and pay related fees and expenses, including existing borrowings under ETE's revolving credit facility and for general partnership purposes. Upon closing, the new senior secured credit facility, combined with proceeds from the Citrus Acquisition, is expected to replace the previously announced $3.7 billion Bridge Term Facility.
We expect ETP and Regency to utilize their resources, along with cash from their operations, to fund their announced growth capital expenditures and working capital needs; however, the Parent Company may issue debt or equity securities from time to time, as we deem prudent to provide liquidity for new capital projects of our subsidiaries or for other partnership purposes.

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ETP
ETP’s ability to satisfy its obligations and pay distributions to its Unitholders will depend on its future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond the control of ETP’s management.
ETP currently believes that its business has the following future capital requirements:
growth capital expenditures for its midstream and intrastate transportation and storage operations, primarily for construction of new pipelines and compression facilities, for which ETP expects to spend between $800 million and $900 million in 2012;
growth capital expenditures for its NGL transportation and services operations of between $1.3 billion and $1.5 billion in 2012, for which ETP expects to receive capital contributions from Regency related to their 30% interest in Lone Star of between $350 million and $400 million; and
maintenance capital expenditures of between $130 million and $140 million in 2012, which include (i) capital expenditures for its intrastate operations for pipeline integrity and for connecting additional wells to its intrastate natural gas systems in order to maintain or increase throughput on existing assets; (ii) capital expenditures for its interstate operations, primarily for pipeline integrity; and (iii) capital expenditures related to NGL transportation and services, which includes amounts ETP expects to be funded by Regency related to its 30% interest in Lone Star.
ETP does not expect to make any growth capital expenditures in 2012 related to its interstate transportation operations.
The assets used in ETP's natural gas operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures. Accordingly, ETP does not have any significant financial commitments for maintenance capital expenditures in its businesses. From time to time it experiences increases in pipe costs due to a number of reasons, including but not limited to, replacing pipe caused by delays from mills, limited selection of mills capable of producing large diameter pipe timely, higher steel prices and other factors beyond ETP's control. However, ETP includes these factors into its anticipated growth capital expenditures for each year.
As discussed in Note 3 to our consolidated financial statements, ETP entered into the Amended Citrus Merger Agreement on July 19, 2011. In January 2012, ETP issued senior notes to fund substantially all of the cash portion of the purchase price. ETP also intends to issue sufficient additional equity to maintain its investment grade credit rating and to use the proceeds from such equity issuances to repay other indebtedness and fund capital expenditures. In addition, ETP may enter into other acquisitions, including the potential acquisition of new pipeline systems.
ETP generally funds its capital requirements with cash flows from operating activities and, to the extent that they exceed cash flows from operating activities, with proceeds of borrowings under existing credit facilities, long-term debt, the issuance of additional common units or a combination thereof.
ETP Recently amended its revolving credit facility to, among other things, increase the capacity from $2.0 billion to $2.5 billion and extend the maturity date to 2016. As of December 31, 2011, in addition to approximately $106.8 million of cash on hand, ETP had available capacity under the ETP revolving credit facility (“ETP Credit Facility”) of approximately $2.16 billion. Based on current estimates, ETP expects to utilize capacity under the ETP Credit Facility, along with cash from ETP’s operations, to fund its announced growth capital expenditures and working capital needs through the end of 2012; however, ETP may issue debt or equity securities prior to that time as it deems prudent to provide liquidity for new capital projects, to maintain investment grade credit metrics or other partnership purposes.

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Regency
Regency expects to funds its capital requirements with cash flows from its operating activities and, to the extent that they exceed cash flows from operating activities, with proceeds of borrowings under its existing credit facility (the "Regency Credit Facility"), operating lease facilities, asset sales, debt offerings and the issuance of additional common units or a combination thereof. As of December 31, 2011, in addition to approximately $1.0 million of cash on hand, Regency had available capacity under the Regency Credit Facility of approximately $549.0 million.
Regency currently expects its capital expenditures to be as follows:
growth capital expenditures of $245 million in 2012 for its gathering and processing operations;
growth capital expenditures of $70 million in 2012 for its contract compression operations;
growth capital expenditures of $15 million in 2012 for its contract treating operations;
capital contributions in relation to its respective ownership interest in joint ventures of between $385million and $435 million in 2012 for its joint venture operations, which includes between $350 million and $400 million to Lone Star and $35 million to Ranch JV;
capital expenditures of $5 million in 2012 for its corporate and others operations; and
maintenance capital expenditures, including Regency's proportionate share related to joint ventures, of $28 million in 2012.
Regency may revise the timing of these expenditures as necessary to adapt to economic conditions. Regency expects to fund its growth capital expenditures with borrowings under its revolving credit facility and a combination of debt and equity issuances.
Cash Flows
Our cash flows may change in the future due to a number of factors, some of which we cannot control. These factors include regulatory changes, the price for ETP’s and Regency’s products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions, and other factors.
For the discussion that follows, certain amounts in prior periods have been reclassified to conform to the 2011 presentation.
Operating Activities
Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” above), excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation and amortization expense and non-cash compensation expense. The increase in depreciation and amortization expense during the periods presented primarily resulted from construction and acquisition of assets, while changes in non-cash unit-based compensation expense result from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring, such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when ETP has a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of price risk management assets and liabilities, timing of accounts receivable collection, payments on accounts payable, the timing of purchases and sales of inventories, and the timing of advances and deposits received from customers.
Following is a summary of operating activities by period:
Year Ended December 31, 2011
Cash provided by operating activities in 2011 was $1.38 billion and net income was $528.2 million. The difference between net income and cash provided by operating activities in 2011 consisted of non-cash items totaling $687.2 million and changes in operating assets and liabilities of $158.1 million. The difference between net income and the net cash provided by operating activities also included distributions received from affiliates that exceeded equity in earnings by $3.1 million. The non-cash activity consisted primarily of depreciation and amortization of $611.8 million and non-cash compensation expense of $42.2 million.

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Year Ended December 31, 2010
Cash provided by operating activities in 2010 was $1.09 billion and net income was $336.6 million. The difference between net income and cash provided by operating activities in 2010 consisted of non-cash items totaling $552.8 million and changes in operating assets and liabilities of $259.5 million. The difference between net income and the net cash provided by operating activities also included ETP interest rate swap termination proceeds of $26.5 million, ETE payments to terminate interest rate swaps of $168.6 million and distributions received from our affiliates that exceeded our equity in earnings by $80.0 million. The non-cash activity consisted primarily of depreciation and amortization of $431.2 million and an impairment in ETP’s investment of an affiliate of $52.6 million. In addition, non-cash compensation expense was $31.2 million. These amounts are partially offset by the allowance for equity funds used during construction of $28.9 million.
Year Ended December 31, 2009
Cash provided by operating activities in 2009 was $723.5 million and net income was $697.9 million. The difference between net income and cash provided by operating activities in 2009 consisted of non-cash items totaling $371.0 million (principally depreciation and amortization expense of $325.0 million and non-cash compensation of $25.8 million, partially offset by the allowance for equity funds used during construction of $10.6 million), offset by changes in operating assets and liabilities of $348.6 million.
Investing Activities
Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, and cash contributions to ETP’s and Regency’s joint ventures. Changes in capital expenditures between periods primarily result from increases or decreases in ETP’s or Regency’s growth capital expenditures to fund their respective construction and expansion projects.
Following is a summary of investing activities by period:
Year Ended December 31, 2011
Cash used in investing activities in 2011 of $3.87 billion was comprised primarily of capital expenditures of $1.81 billion (excluding the allowance for equity funds used during construction), including changes in accruals of $97.8 million. ETP invested $1.42 billion for growth capital expenditures and $134.2 million for maintenance capital expenditures during 2011. Regency invested $354 million for growth capital expenditures and $22 million for maintenance capital during 2011. In addition, our subsidiaries paid cash for acquisitions of $1.97 billion, which primarily consisted of the acquisition of Lone Star and made net advances to joint ventures of $149.7 million.
Year Ended December 31, 2010
Cash used in investing activities in 2010 of $1.83 billion was comprised primarily of total capital expenditures of $1.51 billion (excluding the allowance for equity funds used during construction), including changes in accruals of $44.1 million. ETP invested $1.29 billion for growth capital expenditures in 2010 (primarily related to the Tiger pipeline) and $99.3 million for maintenance capital expenditures. Regency invested $152.3 million for growth capital expenditures and $6.9 million for maintenance capital expenditures between May 26, 2010 and December 31, 2010. In addition, Regency paid cash for acquisitions of $191.3 million, ETP paid cash for acquisitions of $177.9 million, and we received $24.0 million in cash from the acquisition of Regency. Regency received $70.2 million in cash for the sale of its East Texas assets. Our subsidiaries made advances to joint ventures of $92.6 million.
Year Ended December 31, 2009
Cash used in investing activities in 2009 of $1.35 billion was comprised primarily of $530.3 million invested for growth capital expenditures (excluding the allowance for equity funds used during construction), including changes in accruals of $115.7 million. Total growth capital expenditures consist of $412.0 million for ETP’s midstream and intrastate transportation and storage operations, $78.9 million for ETP’s interstate operations, and $39.5 million for ETP’s propane operations. We also incurred $102.7 million in maintenance expenditures needed to sustain operations of which $65.0 million related to ETP’s midstream and intrastate operations, $13.2 million related to ETP’s interstate operations, and $24.4 million related to ETP’s propane operations. In addition, ETP made advances to MEP of $664.5 million and received a reimbursement from FEP of all of its contributions, including $9.0 million that it contributed in 2008. As a result of ETP’s acquisition of a natural gas compression equipment business in exchange for ETP Common Units, cash acquired in connection with acquisitions in 2009 exceeded the cash paid by $30.4 million.

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Financing Activities
Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund ETP’s and Regency’s acquisitions and growth capital expenditures. Distributions increase between the periods based on increases in the number of common units outstanding or increases in the distribution rate.
Following is a summary of financing activities by period:
Year Ended December 31, 2011
Cash provided by financing activities was $2.54 billion in 2011. ETP received $1.47 billion in net proceeds from offerings of ETP Common Units, including $96.3 million under its equity distribution program (see Note 8 to our consolidated financial statements). In addition, Regency received $435.7 million in net proceeds from offerings of Regency Common Units. We had a consolidated net increase in our debt level of $2.00 billion and paid distributions of $525.6 million to our common unitholders and $24.0 million to the holders of our Preferred Units. In addition, ETP paid distributions of $561.5 million on limited partner interests other than those held by the Parent Company and Regency paid $217.0 million on limited partner interests other than those held by the Parent Company. These distributions are reflected as distributions to noncontrolling interests on our consolidated statements of cash flows.
Year Ended December 31, 2010
Cash provided by financing activities was $761.0 million in 2010. ETP received $1.15 billion in net proceeds from offerings of ETP Common Units, including $239.3 million under ETP’s equity distribution program. In addition, Regency received $399.6 million in net proceeds from offerings of Regency Common Units. We had a consolidated net increase in our debt level of $310.4 million and paid distributions of $483.0 million to our common unitholders and $14.4 million to our preferred unitholders. In addition, ETP paid distributions of $475.7 million on limited partner interests other than those held by the Parent Company, and Regency paid $91.9 million on limited partner interests other than those held by the Parent Company. These distributions are reflected as distributions to noncontrolling interests on our consolidated statements of cash flows.
Financing activities in 2010 also include the Parent Company’s completion of $1.8 billion of senior notes in September 2010, the proceeds of which were used to repay outstanding indebtedness under existing credit facilities.
Year Ended December 31, 2009
Cash provided by financing activities was $598.6 million in 2009. ETP received $936.3 million in net proceeds from equity offerings of ETP, including $81.5 million under ETP’s equity distribution program. Net proceeds from ETP’s equity offerings were used to repay borrowings under the ETP Credit Facility, to fund capital expenditures and capital contributions to joint ventures, as well as for general partnership purposes. In 2009, we had a net increase in our consolidated debt level of $522.0 million primarily due to borrowings to fund capital expenditures and to fund capital contributions to joint ventures, partially offset by the use of proceeds from ETP’s Common Unit offerings. ETP also received net proceeds of approximately $993.6 million from the issuance of senior notes which were used to repay outstanding borrowings under the ETP Credit Facility and for general partnership purposes. In addition, Transwestern issued $350.0 million of senior notes, the proceeds from which were used to repay a portion of outstanding amounts under Transwestern’s intercompany loan agreement. ETP in turn, used the proceeds from Transwestern’s intercompany loan repayment to outstanding borrowings under the ETP Credit Facility. In 2009, we paid distributions of $470.7 million to our partners. In addition, ETP paid distributions of $381.5 million on limited partner interests other than those held by the Parent Company. These distributions are reflected as distributions to noncontrolling interests on our consolidated statements of cash flows.

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Description of Indebtedness
Our outstanding consolidated indebtedness was as follows (in thousands):
 
 
Pro Forma December 31, 2011 (1)
 
Actual at December 31,
 
 
2011
 
2010
Parent Company Indebtedness:
 
 
 
 
 
ETE Senior Notes
$
1,800,000

 
$
1,800,000

 
$
1,800,000

ETE senior secured revolving credit facilities
71,500

 
71,500

 

Subsidiary Indebtedness:
 
 
 
 
 
ETP Senior Notes
7,800,000

 
6,550,000


5,050,000

Regency Senior Notes
1,350,000

 
1,350,000

 
850,000

Transwestern Senior Unsecured Notes
870,000

 
870,000

 
870,000

HOLP Senior Secured Notes

 
71,314

 
103,127

ETP Revolving Credit Facility
314,438