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ETE-12.31.2012-10K

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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, 2012



¨	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 29, 2012, 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 $8.60 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 21, 2013, the registrant had 279,961,650 Common Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

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PART I
		PAGE

ITEM 1.	BUSINESS	4

ITEM 1A.	RISK FACTORS	31

ITEM 1B.	UNRESOLVED STAFF COMMENTS	62

ITEM 2.	PROPERTIES	62

ITEM 3.	LEGAL PROCEEDINGS	62

ITEM 4.	MINE SAFETY DISCLOSURES	62

PART II

ITEM 5.	MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	63

ITEM 6.	SELECTED FINANCIAL DATA	64

ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	65

ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	108

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	114

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	114

ITEM 9A.	CONTROLS AND PROCEDURES	114

ITEM 9B.	OTHER INFORMATION	116

PART III

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	116

ITEM 11.	EXECUTIVE COMPENSATION	121

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS	133

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	135

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	136

PART IV

ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	137

Signatures		138

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Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Equity, L.P. (“ETE,” “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, forecasted, expressed 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

AmeriGas		AmeriGas Partners, L.P.

AOCI		accumulated other comprehensive income (loss)

AROs		asset retirement obligations

Bbls		barrels

Bcf		billion cubic feet

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

Canyon		ETC Canyon Pipeline, LLC

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

Citrus		Citrus Corp., which owns 100% of FGT

Citrus Acquisition		ETP’s acquisition of Citrus Corp. on March 26, 2012

CrossCountry		CrossCountry Energy, LLC

CFTC		Commodities Futures Trading Commission

DRIP		Distribution Reinvestment Plan

DOT		U.S. Department of Transportation

Enterprise		Enterprise Products Partners L.P., together with its subsidiaries

ETC OLP		La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company

ETG		Energy Transfer Group, L.L.C.

ETP		Energy Transfer Partners, L.P.

ETP Credit Facility		ETP’s revolving credit facility

ETP GP		Energy Transfer Partners GP, L.P., the general partner of ETP

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ETP LLC		Energy Transfer Partners, L.L.C., the general partner of ETP GP

EPA		U.S. Environmental Protection Agency

Exchange Act		Securities Exchange Act of 1934

FDOT/FTE		Florida Department of Transportation, Florida’s Turnpike Enterprise

FEP		Fayetteville Express Pipeline LLC

FERC		Federal Energy Regulatory Commission

FGT		Florida Gas Transmission Company, LLC, which owns a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula

Finance Company		AmeriGas Finance LLC

GAAP		accounting principles generally accepted in the United States of America

General Partner		LE GP, LLC, the general partner of ETE

HPC		RIGS Haynesville Partnership Co.

Holdco		ETP Holdco Corporation

HOLP		Heritage Operating, L.P.

IDRs		incentive distribution rights

LDH		LDH Energy Asset Holdings LLC, a wholly-owned subsidiary of Louis Dreyfus Highbridge Energy LLC (subsequently renamed Castleton Commodities International, LLC)

LIBOR		London Interbank Offered Rate

LNG		Liquefied natural gas

LNG Holdings		Trunkline LNG Holdings, LLC

LPG		liquefied petroleum gas

Lone Star		Lone Star NGL LLC

MDPU		Massachusetts Department of Public Utilities

MEP		Midcontinent Express Pipeline LLC

MGP		manufactured gas plant

MMBtu		million British thermal units

MMcf		million cubic feet

NGL		natural gas liquid, such as propane, butane and natural gasoline

NMED		New Mexico Environmental Department

NOL		net operating loss

NYMEX		New York Mercantile Exchange

NYSE		New York Stock Exchange

Other Post-retirement Plans		postretirement health care and life insurance plans

OSHA		Federal Occupational Safety and Health Act

Panhandle		Panhandle Eastern Pipe Line Company, LP and its subsidiaries

PCB		polychlorinated biphenyl

Pension Plans		funded non-contributory defined benefit pension plans

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PEPL		Panhandle Eastern Pipe Line Company, LP

PES		Philadelphia Energy Solutions

PHMSA		Pipeline Hazardous Materials Safety Administration

RIGS		Regency Intrastate Gas System

RGS		Regency Gas Services, a wholly owned subsidiary of Regency

Preferred Units		ETE’s Series A Convertible Preferred Units

Propane Business		Heritage Operating, L.P. and Titan Energy Partners, L.P.

Ranch JV		Ranch Westex JV LLC

Regency		Regency Energy Partners LP

Regency GP		Regency Energy Partners GP LP, the general partner of Regency

Regency LLC		Regency Energy Partners GP LLC, the general partner of Regency GP

Regency Preferred Units		Regency’s Series A Convertible Preferred Units, the Preferred Units of a Subsidiary

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

Sea Robin		Sea Robin Pipeline Company, LLC

SEC		Securities and Exchange Commission

Southern Union		Southern Union Company

Southern Union Credit Facility		Southern Union’s revolving credit facility

Southwest Gas		Pan Gas Storage, LLC

SUGS		Southern Union Gas Services

Sunoco		Sunoco, Inc.

Sunoco Logistics		Sunoco Logistics Partners L.P.

TCEQ		Texas Commission on Environmental Quality

Tcf		trillion cubic feet

Titan		Titan Energy Partners, L.P.

Transwestern		Transwestern Pipeline Company, LLC

Trunkline		Trunkline Gas Company, LLC

Trunkline LNG		Trunkline LNG Company, LLC

WTI		West Texas Intermediate Crude

Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, loss on extinguishment of debt, gain on deconsolidation of ETP’s Propane Business and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership's proportionate ownership and amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries' results of operations and for unconsolidated affiliates based on the Partnership's proportionate ownership.

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PART I

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 NYSE under the ticker symbol “ETE.”

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, Regency, Regency GP, Regency LLC, Southern Union, Sunoco, Sunoco Logistics and Holdco. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

On March 26, 2012, we acquired all of the outstanding shares of Southern Union and contributed our ownership in Southern Union for a 60% interest in Holdco at the time of ETP's acquisition of Sunoco on October 5, 2012.

At December 31, 2012, 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	0.9	%	100	%	50,226,967
Regency	1.6	%	100	%	26,266,791

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 subsidiaries.

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Organizational Structure

The following chart summarizes our organizational structure as of December 31, 2012:

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Strategic Transactions

Our significant strategic transactions in 2012 included the following, as discussed in more detail herein:

•

On January 12, 2012, ETP contributed its propane operations, consisting of HOLP and Titan (collectively, the “Propane Business”) to AmeriGas. ETP received approximately $1.46 billion in cash and approximately 30 million AmeriGas common units. AmeriGas assumed approximately $71 million of existing HOLP debt. In connection with the closing of this transaction, ETP entered into a support agreement with AmeriGas pursuant to which ETP is obligated to provide contingent, residual support of $1.5 billion of intercompany indebtedness owed by AmeriGas to a finance subsidiary that in turn supports the repayment of $1.5 billion of senior notes issued by this AmeriGas finance subsidiary to finance the cash portion of the purchase price.

•

On March 26, 2012, we acquired all of the outstanding shares of Southern Union for approximately $3.01 billion in cash and approximately 57 million ETE Common Units. In connection with the Southern Union Merger on March 26, 2012, ETP completed its acquisition of CrossCountry, a subsidiary of Southern Union which owned an indirect 50% interest in Citrus, the owner of FGT. The total merger consideration was approximately $2.0 billion, consisting of approximately $1.9 billion in cash and approximately 2.25 million ETP Common Units.


•	On October 5, 2012, ETP completed its merger with Sunoco. Under the terms of the merger agreement, Sunoco shareholders received a total of approximately 55 million ETP Common Units and approximately $2.6 billion in cash (the "Sunoco merger").

•

Immediately following the closing of the Sunoco merger, ETE contributed its interest in Southern Union into ETP Holdco Corporation, an ETP-controlled entity, in exchange for a 60% equity interest in Holdco. In conjunction with ETE's contribution, ETP contributed its interest in Sunoco to Holdco and retained a 40% equity interest in Holdco. Prior to the contribution of Sunoco to Holdco, Sunoco contributed $2.0 billion of cash and its interests in Sunoco Logistics to ETP in exchange for 90,706,000 ETP Class F Units representing limited partner interests in ETP. We refer to this as the "Holdco Transaction." Pursuant to a stockholders agreement between ETE and ETP, ETP controls Holdco. Consequently, ETP consolidates Holdco (including Sunoco and Southern Union) in its financial statements subsequent to consummation of the Holdco Transaction.

•

In December 2012, Southern Union entered into a purchase and sale agreement pursuant to which subsidiaries of Laclede Gas Company, Inc. have agreed to acquire the assets of Southern Union's Missouri Gas Energy and New England Gas Company divisions. Total consideration for the acquisitions will be $1.035 billion, subject to customary closing adjustments, less the assumption of approximately $19 million of debt. On February 11, 2013, the Laclede Entities announced that it had entered into an agreement with Algonquin Power & Utilities Corp ("APUC") that will allow a subsidiary of APUC to assume the right of the Laclede Entities to purchase the assets of Southern Union's New England Gas Company division, subject to certain approvals. It is expected that the transactions contemplated by the purchase and sale agreements will close by the end of the third quarter of 2013.

•

On February 27, 2013, Southern Union entered into a definitive contribution agreement to contribute to Regency all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS. The consideration to be paid by Regency in connection with this transaction will consist of (i) the issuance of 31,372,419 Regency common units to Southern Union, (ii) the issuance of 6,274,483 Regency Class F units to Southern Union, (iii) the distribution of $570 million in cash to Southern Union, and (iv) the payment of $30 million in cash to a subsidiary of ETP. The Regency Class F units will have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis. Upon the closing of the transaction, we will agree to forego all distributions with respect to our IDRs on the Regency common units issued in the transaction for the first eight consecutive quarters following the closing. The transaction is expected to close in the second quarter of 2013.

Business Strategy

Our primary business objective is to increase cash available for distributions to our unit holders by actively assisting our subsidiaries 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 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.

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Segment Overview

Subsequent to the Holdco Transaction on October 5, 2012, as described above, our reportable segments changed and currently consist of the following:


•	Intrastate Transportation and Storage — consists of assets and operations held by ETP;

•Interstate Transportation and Storage — consists of assets and operations held by ETP and Southern Union;

•Midstream — consists of assets and operations held by ETP and Southern Union;

•NGL Transportation and Services — consists of assets and operations held by ETP and Lone Star;

•Retail Marketing — consists of retail marketing operations held by Sunoco;

•Investment in Sunoco Logistics — consists of ETP's interest in Sunoco Logistics;

•Investment in Regency — consists of the Parent Company's interest in Regency; and

•Corporate and Other — consists of various operations held by multiple subsidiaries, as described below.

The businesses within these segments are described below. See Note 15 to our consolidated financial statements for additional financial information about our reportable segments.

Intrastate Transportation and Storage Segment

Through ETC OLP, we own the largest intrastate pipeline system in the United States with interconnects to Texas markets and to major consumption areas throughout the United States. Our intrastate transportation and storage segment 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 our Oasis pipeline, our East Texas pipeline, our natural gas pipeline and storage assets that we refer to as ET Fuel System, and our HPL System, which are described below.

Our intrastate transportation and storage segment’s results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our 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.

We also generate 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 our HPL System. Generally, we purchase natural gas from either the market (including purchases from our midstream segment’s 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, our intrastate transportation and storage segment generates revenues from fees charged for storing customers’ working natural gas in our storage facilities and from margin from managing natural gas for our own account. The major customers on our intrastate pipelines include Kinder Morgan, Natural Gas Exchange, Inc., XTO Energy, Inc., Total Gas & Power North America and EDF Trading North America, Inc.

Interstate Transportation and Storage Segment

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. Through our interstate transportation and storage segment, we directly own and operate approximately 12,700 miles of interstate natural gas pipeline and have a 50% interest in the joint venture that owns the 185-mile Fayetteville Express pipeline. ETP also owns a 50% interest in Citrus which owns 100% of FGT, an approximately 5,400 mile pipeline system that extends from south Texas through the Gulf Coast to south Florida.

Our interstate transportation and storage segment includes Panhandle, a wholly owned subsidiary of Southern Union, which is owned by Holdco. Panhandle owns and operates a large natural gas open-access interstate pipeline network. The pipeline network,

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consisting of the PEPL, Trunkline and Sea Robin transmission systems, serves customers in the Midwest, Gulf Coast and Midcontinent United States with a comprehensive array of transportation and storage services. In connection with its natural gas pipeline transmission and storage systems, Panhandle has five natural gas storage fields located in Illinois, Kansas, Louisiana, Michigan and Oklahoma. Southwest Gas operates four of these fields and Trunkline operates one. Through Trunkline LNG, Panhandle owns and operates an LNG terminal in Lake Charles, Louisiana.

The results from our interstate transportation and storage segment are primarily derived from the fees we earn from natural gas transportation and storage services. The major customers on our interstate pipelines include Chesapeake Energy Marketing, Inc., EnCana Marketing (USA), Inc. (“EnCana”), Shell Energy North America (US), L.P., BG LNG Services, ProLiance Energy, LLC and Petrohawk Energy Corporation.

We are currently developing plans to convert existing pipeline assets from natural gas transportation to crude oil transportation. These plans include the proposed abandonment of certain pipeline segments of Trunkline Gas Company, LLC (“Trunkline”), a subsidiary of Southern Union, which are currently operating in natural gas service, and the conversion of some or all of those segments of pipeline to crude oil transportation service. Trunkline's application to abandon those segments of pipeline from natural gas service, filed July 26, 2011, is currently pending before the FERC. As of February 13, 2013, the Partnership and Enbridge (U.S.), Inc. entered into an agreement under which they will jointly market a project to transport up to 400,000 Bbls/d of crude oil from Patoka, Illinois, to refinery markets in and around Memphis, Tennessee, Baton Rouge, Louisiana, and St. James, Louisiana, utilizing a combination of newly constructed pipeline and approximately 574 miles of pipeline to be abandoned by Trunkline. Subject to receipt of sufficient customer commitments for long-term transportation capacity and regulatory approvals, this project is expected to be in service by 2015.

We are currently studying the commercial and engineering feasibility of constructing a liquefaction facility at Southern Union's existing Lake Charles LNG regasification terminal. The project is anticipated to utilize a portion of the existing LNG regasification infrastructure, including storage tanks and terminal facilities, and is expected to have the capacity to export up to 2.0 Bcf/d of LNG. We are currently in commercial negotiations with counterparties. We expect to complete certain studies, permits and approvals through 2014, and we do not anticipate making any significant capital expenditures related to this project prior to the completion of those items.

Midstream Segment

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 is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

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.

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 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.

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.

Through our midstream segment, we own and operate approximately 6,700 miles of in service natural gas and NGL gathering pipelines, 4 natural gas processing plants, 15 natural gas treating facilities and 3 natural gas conditioning facilities. Our midstream segment focuses on the gathering, compression, treating, blending, processing and marketing of natural gas, and our operations are currently concentrated in major producing basins and shales, including the Austin Chalk trend and Eagle Ford Shale in South

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and Southeast Texas, the Permian Basin in West Texas and New Mexico, the Barnett Shale and Woodford Shale in North Texas, the Bossier Sands in East Texas, the Marcellus Shale in West Virginia, and the Haynesville Shale in East Texas and Louisiana. Many of our midstream assets are integrated with our intrastate transportation and storage assets.

Our midstream segment results are derived primarily from margins we earn for natural gas volumes that are gathered, transported, purchased and sold through our pipeline systems and the natural gas and NGL volumes processed at our processing and treating facilities. We also market natural gas on our 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 our customers. The major customers on our midstream pipelines include Enterprise, ConocoPhillips Company, Andrews Oil Buyers, Inc. and Chevron Phillips Chemical Company LP.

SUGS’ operations consist of a network of natural gas and NGL pipelines, six processing plants and seven natural gas treating facilities. The principal assets of SUGS are located in the Permian Basin of Texas and New Mexico.

SUGS is primarily engaged in connecting producing wells of exploration and production companies to its gathering system, providing compression and gathering services, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGL, and redelivering natural gas and NGLs to a variety of markets. SUGS’ natural gas supply contracts primarily include fee-based, percent-of-proceeds, and margin sharing contracts (conditioning fee and wellhead purchase contracts). SUGS’ primary sales customers include E&P companies, power generating companies, electric and natural gas utilities, energy marketers, industrial end-users located primarily in the Gulf Coast and southwestern United States, and petrochemicals. With respect to customer demand for the products and services it provides, SUGS’ business is not generally seasonal in nature; however, SUGS’ operations and the operations of its E&P producers can be adversely impacted by severe weather.

NGL Transportation and Services Segment

NGL transportation pipelines transport mixed NGLs and other hydrocarbons from natural gas processing facilities to fractionation plants and storage facilities. 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. NGL fractionators separate mixed NGL streams into purity products, such as ethane, propane, normal butane, isobutane and natural gasoline.

Through our NGL transportation and services segment we own and operate approximately 300 miles of NGL pipelines and have a 50% interest in the Liberty pipeline, an approximately 85-mile NGL pipeline. ETP also has a 70% interest in Lone Star and Regency owns the remaining 30% interest, which owns approximately 2,000 miles of NGL pipelines, three NGL processing plants, two fractionation facilities and NGL storage facilities with aggregate working storage capacity of approximately 47 million Bbls. One of the fractionation facilities and the NGL storage facilities are located at Mont Belvieu, Texas, and the NGL pipelines primarily transport NGLs from the Permian and Delaware basis and the Barnett and Eagle Ford Shales to Mont Belvieu.

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.

This segment also includes revenues earned from processing and fractionating refinery off-gas. Under these contracts we receive an Olefins-grade ("O-grade") stream from cryogenic processing plants located at refineries and fractionate the products into their pure components. We deliver 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, we have percent-of-proceeds and income sharing contracts, which are subject to market pricing of olefins and NGLs. For percent-of-proceeds contracts, we retain 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

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increase, the value of the portion we retain as a fee increases. Conversely, when NGLs and olefin prices decrease, so does the value of the portion we retain as a fee. Under our income sharing contracts, we pay 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 we retain as a fee increases. Conversely, when NGLs and olefins prices decrease as compared to natural gas prices, so does the value of the percent we retain as a fee. The major customers on our NGL pipelines include Targa Resources Partners LP, Louis Dreyfus Highbridge Energy LLC (subsequently renamed Castleton Commodities International, LLC) and The Williams Companies, Inc.

Retail Marketing

Our retail marketing and wholesale distribution business segment consists of Sunoco's marketing operations, which sell gasoline and middle distillates at retail and operates convenience stores in 25 states, primarily on the east coast and in the midwest region of the United States. The highest concentrations of outlets are located in Connecticut, Florida, Maryland, Massachusetts, Michigan, New Jersey, New York, Ohio, Pennsylvania and Virginia.

Investment in Sunoco Logistics

The Partnership's interests in Sunoco Logistics consist of a 2% general partner interest, 100% of the incentive distribution rights and 33,530,637 Sunoco Logistics Common Units representing 32% of the limited partner interests in Sunoco Logistics as of December 31, 2012. Because the Partnership controls Sunoco Logistics through its ownership of the general partner, the operations of Sunoco Logistics are consolidated into the Partnership. These operations are reflected by the Partnership in the investment in Sunoco Logistics segment.

Sunoco Logistics' crude oil pipelines transport crude oil principally in Oklahoma and Texas. Crude oil transportation pipelines primarily deliver to and connect with other pipelines that deliver crude oil to a number of third-party refineries. Sunoco Logistics' crude oil pipelines consist of approximately 4,900 miles of crude oil trunk pipelines and approximately 500 miles of crude oil gathering lines that supply the trunk pipelines.

Sunoco Logistics' crude oil acquisition and marketing business gathers, purchases, markets and sells crude oil principally in the mid-continent United States, utilizing its fleet of approximately 200 crude oil transport trucks, approximately 120 crude oil truck unloading facilities and third-party assets.

Sunoco Logistics' refined terminal facilities receive refined products from pipelines, barges, railcars and trucks and transfer them to or from storage or transportation systems, such as pipelines, to other transportation systems, such as trucks or other pipelines. Sunoco Logistics' terminal facilities consist of an aggregate crude oil and refined petroleum products capacity of approximately 40 million barrels, including the 22 million barrel Nederland, Texas crude oil terminal; the 5 million barrel Eagle Point, New Jersey refined petroleum products and crude oil terminal; approximately 40 active refined petroleum products marketing terminals located in the northeast, midwest and southwest United States; and several refinery terminals located in the northeast United States.

Sunoco Logistics' refined product pipelines transport refined products including multiple grades of gasoline, middle distillates (such as heating oil, diesel and jet fuel) and LPGs (such as propane and butane) from refineries to markets. Sunoco Logistics' refined products pipelines consist of approximately 2,500 miles of refined product pipelines and joint venture interests in four refined products pipelines in selected areas of the United States.

Investment in Regency

Regency’s operations include the following:

Gathering 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. This segment also includes Regency's 33.33% membership interest in Ranch JV, which processes natural gas delivered from the NGLs-rich Bone Spring and Avalon shale formations in West Texas.

Natural Gas Transportation Operations

Regency owns a 49.99% general partners interest in HPC, which owns RIGS, a 450-mile intrastate pipeline that delivers natural gas from Northwest Louisiana to downstream pipelines and markets, and a 50% membership interest in MEP, which owns an interstate natural gas pipeline with approximately 500 miles stretching from Southeast Oklahoma through Northwest Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental Gas Pipe Line system in Butler, Alabama.

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This segment also includes Gulf States, which owns a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.

NGL Services Operations

Regency owns a 30% membership interest in Lone Star, an entity owning a diverse set of midstream energy assets including pipelines, storage, fractionation and processing facilities located in the states of Texas, Mississippi and Louisiana. ETP owns the remaining 70%.

Contract Services Operations

Regency owns and operates a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. Regency also 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.

All Other

Segments below the quantitative thresholds are classified as “Corporate and Other.” These include the following:


•	activities of the Parent Company;


•	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.; and


•	ETP's corporate and other, which includes the following operating segments that do not meet the qualitative threshold for separate reporting:


◦	ETP owns 100% of the membership interests of Energy Transfer Group, L.L.C. (“ETG”), which owns all of the partnership interests of Energy Transfer Technologies, Ltd. (“ETT”). ETT provides compression services to customers engaged in the transportation of natural gas, including our other segments.


•	We own all of the outstanding equity interests of a natural gas compression equipment business with operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas.


•	ETP owns a 32% limited partner interest in AmeriGas, which is engaged in retail propane marketing. ETP acquired this interest when it contributed its retail propane operations to AmeriGas in January 2012.


•	Southern Union has operations providing local distribution of natural gas in Missouri and Massachusetts. The operations are conducted through the Southern Union’s operating divisions: Missouri Gas Energy and New England Gas Company. As noted in "Strategic Transactions" above, we recently entered into an agreement to sell these operations.


•	Sunoco owns approximately 30% non-operating interest in Philadelphia Energy Solutions (“PES”), a joint venture with The Carlyle Group, L.P. (“The Carlyle Group”), which owns a refinery in Philadelphia. Sunoco has a ten-year supply contract for gasoline and diesel produced at the refinery for its retail marketing business.

Asset Overview

Intrastate Transportation and Storage Segment

The following details our pipelines and storage facilities in the intrastate transportation and storage segment.

ET Fuel System


•	Capacity of 5.2 Bcf/d


•	Approximately 2,875 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 550 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

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shippers on our 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 our 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 our 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 our storage capacity on the ET Fuel System is contracted to third parties under fee-based arrangements that extend through 2017.

In addition, the ET Fuel System is integrated with our Godley processing plant which gives us 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.

Oasis Pipeline


•	Capacity of 1.2 Bcf/d


•	Approximately 600 miles of natural gas pipeline


•	Connects Waha to Katy market hubs


•	Bi-directional capabilities

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 our Southeast Texas System and is an important component to maximizing our 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 us to bypass our 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 5.3 Bcf/d


•	Approximately 3,900 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 us 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 our 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, 2012, we had approximately 12.4 Bcf committed under fee-based arrangements with third parties and approximately 45.7 Bcf stored in the facility for our 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 we own, with our 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 our Reed compressor station in Freestone County to our Grimes County compressor station, the 36-inch Katy expansion connecting Grimes to the Katy Hub, and the 42-inch Southeast Bossier pipeline connecting our Cleburne to Carthage pipeline to the HPL

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System. Key shippers on the East Texas pipeline include XTO and EnCana with an average of approximately 680,000 MMBtu/d and 260,000 MMBtu/d, respectively.

Interstate Transportation Pipelines

The following details our pipelines in the interstate transportation and storage segment.

Florida Gas Transmission Pipeline


•	Capacity of 3.1 Bcf/d


•	Approximately 5,400 miles of interstate natural gas pipeline


•	FGT is owned by Citrus, a 50/50 joint venture with Kinder Morgan, Inc. ("KMI")

The Florida Gas Transmission pipeline is an open-access interstate pipeline system with a mainline capacity of 3.1 Bcf/d and approximately 5,400 miles of pipelines extending from south Texas through the Gulf Coast region of the United States to south Florida. The Florida Gas Transmission pipeline system receives natural gas from various onshore and offshore natural gas producing basins. FGT is the principal transporter of natural gas to the Florida energy market, delivering over 64% of the natural gas consumed in the state. In addition, Florida Gas Transmission's pipeline system operates and maintains over 70 interconnects with major interstate and intrastate natural gas pipelines, which provide FGT's customers access to diverse natural gas producing regions.

FGT's customers include electric utilities, independent power producers, industrials and local distribution companies.

Transwestern Pipeline


•	Capacity of 2.0 Bcf/d


•	Approximately 2,560 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 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.

Panhandle Eastern Pipeline


•	Capacity of 2.8 Bcf/d


•	Approximately 6,000 miles of interstate natural gas pipeline

The Panhandle Eastern pipeline’s transmission system consists of four large diameter pipelines extending approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Indiana, Ohio and into Michigan. Panhandle Eastern pipeline is owned by a subsidiary of Holdco.

Trunkline Gas Pipeline


•	Capacity of 1.7 Bcf/d


•	Approximately 3,000 miles of interstate natural gas pipeline

The Trunkline Gas pipeline’s transmission system consists of two large diameter pipelines extending approximately 1,400 miles from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and to Michigan. Trunkline Gas pipeline is owned by a subsidiary of Holdco.

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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 through 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 through ETC FEP 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.

Sea Robin Pipeline


•	Capacity of 1.9 Bcf/d


•	Approximately 1,000 miles of interstate natural gas pipeline

The Sea Robin pipeline’s transmission system consists of two offshore Louisiana natural gas supply systems extending approximately 81 miles into the Gulf of Mexico. Sea Robin pipeline is owned by a subsidiary of Holdco.

Midstream

The following details our assets in the midstream segment.

Southeast Texas System


•	Approximately 6,200 miles of natural gas pipeline


•	One natural gas processing plant (La Grange) with aggregate capacity of 205 MMcf/d


•	12 natural gas treating facilities with aggregate capacity of 1.8 Bcf/d


•	One natural gas conditioning facility with aggregate capacity of 200 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 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 us to bypass our 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 natural gas processing plant that processes the rich natural gas that flows through our system to produce residue gas and NGLs. Residue gas is delivered into our intrastate pipelines and NGLs are delivered into our recently acquired or completed pipelines.

Our treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into our system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications. In addition, our conditioning facilities remove heavy hydrocarbons from the gas gathered into our systems so the gas can be redelivered and meet downstream pipeline hydrocarbon dew point specifications.

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SUGS


•	Approximately 5,700 miles of natural gas and NGL pipelines


•	Six processing plants with aggregate capacity of 510 MMcf/d

Seven natural gas treating facilities with aggregate capacity of 630 MMcf/d

SUGS owns natural gas and NGL pipelines, processing plants and natural gas treating plants and is engaged in connecting producing wells of exploration and production companies to its gathering system, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGLs and redelivering natural gas and NGLs to a variety of markets in West Texas and New Mexico. SUGS is owned by a subsidiary of Holdco.

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 and Woodford Shales. The system includes our 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 processing plant and a conditioning facility.

Northern Louisiana


•	Approximately 280 miles of natural gas pipeline


•	Three natural gas treating facilities with aggregate capacity of 385 MMcf/d

Our Northern Louisiana assets comprise several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with several pipelines, including our Tiger pipeline. Our Northern Louisiana assets include the Bistineau, Creedence, and Tristate Systems.

Rich Eagle Ford Mainline System


•	Approximately 220 miles of natural gas pipeline


•	Two processing plants (Chisholm and Kenedy) with capacity of 325 MMcf/d

The Rich Eagle Ford Mainline gathering system consists of 30-inch and 42-inch natural gas transportation pipelines delivering 1.0 Bcf/d of capacity originating in Dimmitt County, Texas and extending to our Chisholm pipeline for ultimate deliveries to our existing processing plants. Our Chisholm and Kenedy processing plants are connected to our intrastate transportation pipeline systems for deliveries of residue gas and are also connected with our NGL pipelines for delivery of NGLs.

Other Midstream Assets

The midstream segment also includes our 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. We also own gathering pipelines serving the Marcellus Shale in West Virginia with aggregate capacity of approximately 250 MMcf/d.

Marketing Operations

We conduct marketing operations in which we market the natural gas that flows through our gathering and intrastate transportation assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase 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, we purchase gas or act as an agent for small independent producers that may not have marketing operations. We develop relationships with natural gas producers to facilitate the purchase of their production on a long-term basis. We believe that this business provides us with strategic insight and market intelligence, which may positively impact our expansion and acquisition strategy.

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NGL Transportation and Services

The following details our assets in the NGL transportation and services segment. Certain assets described below are owned by Lone Star, a joint venture with ETP and Regency owning 70% and 30% interests, respectively.

West Texas System


•	Capacity of 137,000 Bbls/d


•	Approximately 1,170 miles of NGL transmission pipelines

The West Texas System, owned by Lone Star, is an intrastate NGL pipeline consisting of 3-inch to 16-inch long-haul, mixed NGLs transportation pipeline that delivers 137,000 Bbls/d 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.

West Texas Gateway Pipeline


•	Initial capacity of 209,000 Bbls/d


•	Approximately 570 miles of NGL transmission pipeline

The West Texas Gateway Pipeline, owned by Lone Star, began service in December 2012 and transports NGLs produced in the Permian and Delaware Basins in West Texas and the Eagle Ford Shale to Mont Belvieu, Texas.

Other NGL Pipelines


•	Capacity ranging from 20,000 to 260,000 Bbls/d


•	Approximately 279 miles of NGL transmission pipelines

Other NGL pipelines include the 126-mile Justice pipeline with capacity of 260,000 Bbls/d, the 87-mile Liberty pipeline with a capacity of 90,000 Bbls/d, the 45-mile Freedom pipeline with a capacity of 40,000 Bbls/d and the 21-mile Spirit pipeline with a capacity of 20,000 Bbls/d.

Mont Belvieu Storage Facilities


•	Working storage capacity of approximately 43 million Bbls


•	Approximately 140 miles of NGL transmission pipelines


•	100,000 Bbls/d fractionation facility

The Mont Belvieu storage facility, owned by Lone Star, 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.

The Long Star Fractionator I, completed in December 2012, handles NGLs delivered from several sources, including Lone Star's West Texas Gateway pipeline and the Justice pipeline.

Hattiesburg Storage Facility


•	Working storage capacity of 4 million Bbls

The Hattiesburg storage facility is an integrated liquids storage facility with approximately 4 million Bbls of salt dome capacity, providing 100% fee-based cash flows.

Sea Robin Processing Plant


•	One processing plant with a total 850 MMcf/d residue capacity and 26,000 Bbls/d NGL capacity


•	20% non-operating interest held by Lone Star

Sea Robin is a 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 850 MMcf/d and an NGL capacity of 26,000 Bbls/d.

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Refinery Services


•	Two processing plants (the Chalmette and Sorrento Plants) with a total capacity of 82 MMcf/d


•	One NGL fractionator with 25,000 Bbls/d capacity


•	Approximately 100 miles of NGL pipelines

Refinery Services, owned by Lone Star, 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 O-grade 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 processing plants.

Retail Marketing

The retail marketing segment consists of the retail sale of gasoline and middle distillates and the operation of convenience stores in 25 states, primarily on the east coast and in the midwest region of the United States. The highest concentrations of outlets are located in Connecticut, Florida, Maryland, Massachusetts, Michigan, New Jersey, New York, Ohio, Pennsylvania and Virginia.

Retail marketing has a portfolio of outlets that differ in various ways including: product distribution to the outlets; site ownership and operation; and types of products and services provided.

Direct outlets may be operated by Sunoco or by an independent dealer, and are sites at which fuel products are delivered directly to the site by Sunoco trucks or by contract carriers. Sunoco or an independent dealer owns or leases the property. These sites may be traditional locations that sell fuel products under the Sunoco® and Coastal® brands or may include APlus® convenience stores or Ultra Service Centers® that provide automotive diagnostics and repair. Included among the direct outlets at December 31, 2012 were 73 outlets on turnpikes and expressways in Pennsylvania, New Jersey, New York, Maryland, Ohio and Delaware. Of these outlets, 57 were Sunoco-operated sites providing gasoline, diesel fuel and convenience store merchandise.

Distributor outlets are sites in which the distributor takes delivery of fuel products at a terminal where branded products are available. Sunoco does not own, lease or operate these locations.

The following table sets forth Sunoco’s retail gasoline outlets at December 31, 2012:



Direct Outlets:
Sunoco-Owned or Leased:
Sunoco Operated:
Traditional		60
APlus® Convenience Stores		377
		437
Dealer Operated:
Traditional		127
APlus® Convenience Stores		233
Ultra Service Centers®		91
		451
Total Sunoco-Owned or Leased ⁽¹⁾		888
Dealer Owned ⁽²⁾		495
Total Direct Outlets		1,383
Distributor Outlets		3,605
		4,988


⁽¹⁾	Gasoline and diesel throughput per Sunoco-operated site averaged 198,000 gallons per month from the merger date.


⁽²⁾	Primarily traditional outlets.

Branded fuels sales (including middle distillates) averaged 318,000 Bbls/d from the merger date.

The Sunoco® brand is positioned as a premium brand. Brand improvements in recent years have focused on physical image, customer service and product offerings. In addition, Sunoco believes its brands and high performance gasoline business have benefited from its sponsorship agreements with NASCAR® and INDYCAR®. Under the sponsorship agreement with NASCAR,

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which continues until 2019, Sunoco® is the Official Fuel of NASCAR® and APlus® is the Official Convenience Store of NASCAR®. Sunoco has exclusive rights to use certain NASCAR® trademarks to advertise and promote Sunoco products and is the exclusive fuel supplier for the three major NASCAR® racing series. Sunoco has an agreement to be the Official Fuel of the INDYCAR® series through the 2014 season.

Sunoco’s APlus® convenience stores are located principally in Florida, New York and Pennsylvania. These stores supplement sales of fuel products with a broad mix of merchandise such as groceries, fast foods, beverages and tobacco products. The following table sets forth information concerning Sunoco’s Company-operated APlus® convenience stores at December 31, 2012:



Number of stores	377
Merchandise sales (thousands of dollars/store/month)	$	106
Merchandise margin (% sales)	26		%

Investment in Sunoco Logistics

Sunoco Logistics is principally engaged in the transport, terminalling and storage of crude oil and refined petroleum products. In addition to logistics services, Sunoco Logistics owns acquisition and marketing assets which are used to facilitate the purchase and sale of crude oil and refined products. Its portfolio of geographically diverse assets earns revenues in 30 states located throughout the United States. Sunoco Logistics also has an ownership interest in several refined product and crude oil pipeline joint ventures.

The following details the assets owned by Sunoco Logistics.

Crude Oil Pipelines

Sunoco Logistics' crude oil pipelines consist of approximately 4,900 miles of crude oil trunk pipelines and approximately 500 miles of crude oil gathering pipelines in the southwest and midwest United States. These lines primarily deliver crude oil and other feedstocks to refineries in those regions. Following is a description of Sunoco Logistics' crude pipelines:


•	West Texas Gulf Pipe Line Company owns approximately 600 miles of common carrier crude oil pipelines, which originate from the West Texas oil fields at Colorado City and the Nederland Terminal and extend to Longview, Texas where deliveries are made to several pipelines, including the Mid-Valley pipeline.


•	Mid-Valley Pipeline Company owns approximately 1,000 miles of crude oil pipelines, which originate in Longview, Texas and terminate in Samaria, Michigan. Mid-Valley provides crude oil to a number of refineries, primarily in the midwest United States.


•	The Southwest United States pipeline system consists of approximately 2,950 miles of crude oil trunk pipelines and approximately 300 miles of crude oil gathering pipelines in Texas. The Texas system is connected to the Mid-Valley pipeline, the West Texas Gulf pipeline, other third-party pipelines and our Nederland Terminal.


•	The Oklahoma crude oil pipeline and gathering system contains approximately 850 miles of crude oil trunk pipelines and approximately 200 miles of crude oil gathering pipelines. We have the ability to deliver substantially all of the crude oil gathered on our Oklahoma system to Cushing.


•	The Midwest United States pipeline system consists of approximately 1,000 miles of a crude oil pipeline that originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio, and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the midwest United States.

Sunoco Logistics also owns approximately 100 miles of crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio, and a truck injection point for local production at Marysville. This pipeline receives crude oil from the Enbridge pipeline system for delivery to refineries located in Toledo, Ohio and to Marathon's Samaria, Michigan tank farm, which supplies its refinery in Detroit, Michigan.

Sunoco Logistics' pipelines access several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, as well as other trading hubs located in Midland, Colorado City and Longview, Texas. Our crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a number of third-party refineries.

Crude Oil Acquisition and Marketing

Sunoco Logistics' crude oil acquisition and marketing activities include the gathering, purchasing, marketing and selling of crude oil primarily in the mid-continent United States. Sunoco Logistics' crude oil truck drivers pick up crude oil at production lease sites and transport it to various truck unloading facilities on our pipelines and third-party pipelines. Third-party trucking firms are also retained to transport crude oil to certain facilities.

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Terminal Facilities

Sunoco Logistics' 41 active refined products terminals receive refined products from pipelines, barges, railcars, and trucks and distribute them to Sunoco and to third parties, who in turn deliver them to end-users and retail outlets. Terminals are facilities where products are transferred to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. The operation of these facilities is called “terminalling.” Terminals play a key role in moving product to the end-user markets by providing the following services: storage; distribution; blending to achieve specified grades of gasoline and middle distillates; and other ancillary services that include the injection of additives and the filtering of jet fuel. Typically, Sunoco Logistics' refined products terminal facilities consist of multiple storage tanks and are equipped with automated truck loading equipment that is operational 24 hours a day. This automated system provides controls over allocations, credit, and carrier certification.

•

The East Boston Terminal is a refined products terminal, located in East Boston, Massachusetts, that receives refined products from affiliates of ConocoPhillips. The terminal is the sole service provider to Logan International Airport under a long-term contract to provide jet fuel. The terminal includes a 10-bay truck rack and total active storage capacity for this facility is approximately 1 million barrels.


•	The Eagle Point Tank farm is located in Westville, New Jersey and consists of approximately 5 million barrels of active storage for clean products and dark oils.


•	The Southwest Terminal is a crude oil and refined products terminal located in Bay City, Texas. The terminal has a total capacity of less than half of a million barrels.

•

A butane blending business generates profits by adding less expensive normal butane to higher priced gasoline, while complying with regional and seasonally variable specifications for maximum vapor pressure. The business provides terminal and pipeline operators with the use of proprietary automated blending systems and butane supply to optimize butane blending in pipelines and at refined products terminals.

Sunoco Logistics' refined products terminals derive revenues from terminalling fees paid by customers. A fee is charged for receiving refined products into the terminal and delivering them to trucks, barges, or pipelines. In addition to terminalling fees, Sunoco Logistics generates revenues by charging customers fees for blending services, including ethanol and biodiesel blending, injecting additives, and filtering jet fuel. Sunoco Logistics' refined products pipelines supply the majority of its refined products terminals, with third-party pipelines and barges supplying the remainder.

The following table outlines the number of Sunoco Logistics' active terminals and storage capacity by state:



State	Number of Terminals	Storage Capacity (thousands of Bbls)
Indiana	1	206
Maryland	1	715
Massachusetts	1	1,160
Michigan	3	762
New Jersey	4	746
New York ⁽¹⁾	4	920
Ohio	7	904
Pennsylvania	13	1,734
Virginia	1	403
Louisiana	1	161
Texas	5	715
Total	41	8,426


(1)	Sunoco Logistics owns a 45% ownership interest in a terminal at Inwood, New York and a 50% ownership interest in a terminal at Syracuse, New York. The storage capacities included in the table represent the proportionate share of capacity attributable to Sunoco Logistics' ownership interests in these terminals.

Sunoco Logistics' Nederland Terminal, which is located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large transporters of crude oil. The terminal receives, stores, and distributes crude oil, feedstocks, lubricants, petrochemicals, and bunker oils (used for fueling ships and other marine vessels), and also blends lubricants. The terminal currently has a total storage capacity of approximately 22 million barrels in approximately 130 aboveground storage tanks with individual capacities of up to 660,000 barrels.

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Sunoco Logistics' Fort Mifflin Terminal Complex is located on the Delaware River in Philadelphia and includes the Fort Mifflin Terminal, the Hog Island Wharf, the Darby Creek tank farm and connecting pipelines. Revenues are generated from the Fort Mifflin Terminal Complex by charging fees based on throughput.

Sunoco Logistics' Marcus Hook tank farm has a total storage capacity of approximately 2 million barrels.

Sunoco Logistics' Eagle Point Terminal docks are located in Westville, New Jersey on the Delaware River and are connected to the Sunoco Eagle Point refinery, which was permanently shut down in the fourth quarter 2009. To complement the services offered by Sunoco Logistics' existing dock and truck loading equipment, Sunoco Logistics acquired the Eagle Point tank farm from Sunoco in July 2011. The tank farm is connected to Sunoco Logistics' previously owned dock facility and allowed us to expand upon the services offered by its existing assets. The tank farm provides crude oil and refined products storage and distribution services and has a total active storage capacity of approximately 5 million barrels for clean products and dark oils. The docks can accommodate three ships or barges to receive and deliver crude oil, intermediate products and refined products to outbound ships and barges.

Sunoco Logistics' Inkster Terminal, located near Detroit, Michigan, consists of eight salt caverns with a total storage capacity of approximately 975,000 barrels. The Inkster Terminal's storage is used in connection with the Toledo, Ohio to Sarnia, Canada pipeline system and for the storage of LPGs from Canada and a refinery in Toledo. The terminal can receive and ship LPGs in both directions at the same time and has a propane truck loading rack.

Refined Products Pipelines

Sunoco Logistics owns and operates approximately 2,500 miles of refined products pipelines in selected areas of the United States. The refined products pipelines transport refined products from refineries in the northeast, midwest and southwest United States to markets in New York, New Jersey, Pennsylvania, Ohio, Michigan, Massachusetts, Texas and Canada. The refined products transported in these pipelines include multiple grades of gasoline, middle distillates (such as heating oil, diesel and jet fuel) and LPGs (such as propane and butane). Rates for shipments on the refined products pipelines are regulated by the FERC and the Pennsylvania Public Utility Commission (“PA PUC”), among other state regulatory agencies.


•	Inland Corporation is Sunoco Logistics' 83.8% owned joint venture consisting of 350 miles of active refined products pipelines in Ohio. The pipeline connects three refineries in Ohio to terminals and major markets in Ohio. As Sunoco Logistics owns a controlling financial interest in Inland, the joint venture is reflected as a consolidated subsidiary in its consolidated financial statements.

Sunoco Logistics owns equity interests in several common carrier refined products pipelines, summarized in the following table:



Pipeline	Equity Ownership		Pipeline Mileage
Explorer Pipeline Company ⁽¹⁾	9.4	%	1,850
Yellowstone Pipe Line Company ⁽²⁾	14.0	%	700
West Shore Pipe Line Company ⁽³⁾	17.1	%	650
Wolverine Pipe Line Company ⁽⁴⁾	31.5	%	700


⁽¹⁾	The system, which is operated by Explorer employees, originates from the refining centers of Lake Charles, Louisiana and Beaumont, Port Arthur and Houston, Texas, and extends to Chicago, Illinois, with delivery points in the Houston, Dallas/Fort Worth, Tulsa, St. Louis, and Chicago areas. Explorer charges market-based rates for all its tariffs.


⁽²⁾	The system, which is operated by Phillips 66, originates from the Billings, Montana refining center and extends to Moses Lake, Washington with delivery points along the way. Tariff rates are regulated by the FERC for interstate shipments and the Montana Public Service Commission for intrastate shipments in Montana.


⁽³⁾	The system, which is operated by Buckeye Partners, L.P., originates from the Chicago, Illinois refining center and extends to Madison and Green Bay, Wisconsin with delivery points along the way. West Shore charges market-based tariff rates in the Chicago area.


⁽⁴⁾	The system, which is operated by Wolverine employees, originates from Chicago, Illinois and extends to Detroit, Grand Haven, and Bay City, Michigan with delivery points along the way. Wolverine charges market-based rates for tariffs at the Detroit, Jackson, Niles, Hammond, and Lockport destinations.

Sunoco has agreements with Sunoco Logistics which establish fees for administrative services provided by Sunoco to Sunoco Logistics and provide indemnifications by Sunoco for certain environmental, toxic tort and other liabilities.

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Investment in Regency

The following details the assets in Regency’s natural gas operations:

Gathering and Processing Operations

North Louisiana Region


•	Approximately 653 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.

In August 2012, Regency announced construction of an expansion of the Dubach processing facility in North Louisiana that will increase the processing capacity of the facility to 210 MMcf/d by adding an incremental 70 MMcf/d of cryogenic processing capacity and 20 MMcf/d of JT capacity. The $75 million capital expenditure related to this expansion also includes the construction of high-pressure gathering lines to bring production to the facility. The project, which is expected to come online in the second quarter of 2013, is backed by fee-based contracts and an acreage dedication.

Through the gathering and processing systems described above and their interconnections with SIGS 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 1,286 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. In May 2012, Regency announced the construction of an expansion which will increase the system's capacity by 90 MMcf/d to 160 MMcf/d, and will provide for additional crude transportation and stabilization capacity of 17,000 Bbls/d. Contracts on the expansion are fee-based, which includes reservation fees. Capital expenditures related to the expansion are expected to total $150 million, of which Regency will contribute $90 million. The project is expected to be completed in mid-2012.

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West Texas Region


•	Approximately 941 miles of natural gas pipeline


•	Two cryogenic natural gas processing plants and a refrigeration 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.

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.

Regency also owns a 33.33% interest in Ranch JV which processes natural gas delivered from the NGLs-rich Bone Spring and Avalon shale formations in West Texas. The joint venture owns a 25 MMcf/d refrigeration plant and a 100 MMcf/d cryogenic processing plant.

Mid-Continent Region


•	Approximately 3,465 miles of natural gas pipeline


•	One processing plant

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. 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.

Natural Gas Transportation Operations

Regency owns a 49.99% general partner interest in HPC, which owns RIGS, a 450-mile intrastate pipeline that delivers natural gas from Northwest Louisiana to downstream pipelines and markets.

Regency owns a 50% membership interest in 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.

Regency also owns a 10-mile pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.

NGL Services Operations

Regency owns 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.

Contract Services 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

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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.

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.

Industry Overview

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.

Demand for oil. Oil continues to be a critical component of energy consumption 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.

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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.

NGL fractionation and processing. NGL fractionators separate mixed NGL streams into purity products, such as ethane, propane, normal butane, isobutane and natural gasoline.

Refined products transportation. Refined product pipelines transport refined products including multiple grades of gasoline, middle distillates (such as heating oil, diesel and jet fuel) and LPGs (such as propane and butane) from refineries to markets.

Terminal facilities. Refined terminal facilities receive refined products from pipelines, barges, railcars and trucks and transfer them to or from storage or transportation systems, such as pipelines, to other transportation systems, such as trucks or other pipelines. Terminals play a key role in moving product to the end-user markets by providing the following services: storage, distribution, blending to achieve specified grades of gasoline and middle distillates; and other ancillary services that include the injection of additives and the filtering of jet fuel.

Crude oil transportation. Crude oil transportation pipelines primarily deliver to and connect with other pipelines that deliver crude oil to a number of third-party refineries.

Retail marketing. Retail marketing business consists of the retail sale of gasoline and middle distillates and the operation of convenience stores.

Competition

Natural Gas

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 our transportation and storage segment are other pipelines. Pipelines typically compete with each other based on location, capacity, price and reliability.

We face competition with respect to retaining and obtaining significant natural gas supplies under terms favorable to us for the gathering, treating and marketing portions of our business. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport and market natural gas. Many of our competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours.

In marketing natural gas, we 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 our marketing operations.

NGL

In markets served by our NGL pipelines, we face competition with other pipeline companies and barge, rail and truck fleet operations. We face competition with other storage facilities based on fees charged and the ability to receive and distribute the customer's products.

Crude and Refined Product

In markets served by our refined products and crude oil pipelines, we face competition with other pipelines. Generally, pipelines are the lowest cost method for long-haul, overland movement of refined products. Therefore, the most significant competitors for large volume shipments in the areas served by our pipelines are other pipelines. In addition, pipeline operations face competition from trucks that deliver product in a number of areas that our pipeline operations serve. While their costs may not be competitive for longer hauls or large volume shipments, trucks compete effectively for incremental and marginal volume in many areas served by our pipelines.

We also face competition among common carrier pipelines carrying crude oil. This competition is based primarily on transportation charges, access to crude oil supply and market demand. Similar to pipelines carrying refined products, the high capital costs deter

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competitors for the crude oil pipeline systems from building new pipelines. Crude oil purchasing and marketing activities’ competitive factors are price and contract flexibility, quantity and quality of services, and accessibility to end markets.

Our refined product terminals compete with other independent terminals with respect to price, versatility and services provided. The competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.

We face strong competition in the market for the sale of retail gasoline and merchandise. Our competitors include service stations of large integrated oil companies, independent gasoline service stations, convenience stores, fast food stores, and other similar retail outlets, some of which are well-recognized national or regional retail systems. The number of competitors varies depending on the geographical area. It also varies with gasoline and convenience store offerings. The principal competitive factors affecting our retail marketing operations include gasoline and diesel acquisition costs, site location, product price, selection and quality, site appearance and cleanliness, hours of operation, store safety, customer loyalty and brand recognition. We compete by pricing gasoline competitively, combining retail gasoline business with convenience stores that provide a wide variety of products, and using advertising and promotional campaigns. We believe that we are in a position to compete effectively as a marketer of refined products because of the location of our retail network, which is well integrated with the distribution system operated by Sunoco Logistics.

Credit Risk and Customers

Our subsidiaries maintain credit policies with regard to our counterparties that we believe significantly reduce overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), requirements for collateral under certain circumstances, and the use of standardized agreements, which allow for netting of positive and negative exposure associated with a single or multiple counterparties.

Our subsidiaries’ 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 our 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, management does not anticipate a material adverse effect on financial position or results of operations as a result of counterparty non-performance.

Our natural gas transportation and midstream revenues are derived significantly from companies that engage in natural gas exploration and production activities. Prices for natural gas have been negatively impacted in recent years by economic conditions and the discovery and development of new shale formations. As a result, many of our customers have been negatively impacted. We are diligent in attempting to mitigate credit risk relating to our customers.

During the year ended December 31, 2012, no individual customer accounted for more than 10% of our consolidated 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 Florida Gas Transmission, Transwestern, Panhandle Eastern, Trunkline Gas, Tiger, Fayetteville Express and Sea Robin pipelines transport natural gas in interstate commerce and thus each qualifies as a “natural gas company” under the NGA subject to FERC’s regulatory jurisdiction. ETP also holds certain storage facilities that are subject to the FERC's regulatory oversight. Additionally, Regency owns an indirect 50% interest in the entity that owns and operates the Midcontinent Express pipeline 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;


•	the extension or abandonment of services and facilities;


•	the maintenance of accounts and records;


•	the acquisition and disposition of facilities; and

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•	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 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.

In July 2010, in response to an intervention and protest filed by BG LNG Services ("BGLS") regarding its rates with Trunkline LNG applicable to certain LNG expansions, FERC determined that there was no reason at that time to expend FERC's resources on a rate proceeding with respect to Trunkline LNG even though cost and revenue studies provided by the Company to FERC indicated Trunkline LNG's revenues were in excess of its associated cost of service. However, since the current fixed rates expire at the end of 2015 and revert to tariff rate for these LNG expansions as well as the base LNG facilities for which rates were set in 2002, a rate proceeding could be initiated at that time and result in significant revenue reductions if the cost of service remains lower than revenues.

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.

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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.

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 and 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 and 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. 5^th 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

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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.

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 Interstate Crude Oil and Refined Products Pipelines. Interstate common carrier pipeline operations are subject to rate regulation by FERC under the Interstate Commerce Act, the Energy Policy Act of 1992, and related rules and orders. The Interstate Commerce Act requires that tariff rates for petroleum pipelines be "just and reasonable" and not unduly discriminatory. This statute also permits interested persons to challenge proposed new or changed rates and authorizes FERC to suspend the effectiveness of such rates for up to seven months and to investigate such rates. If, upon completion of an investigation, FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund revenues in excess of the prior tariff during the term of the investigation. FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.

FERC generally has not investigated interstate rates on its own initiative when those rates, like those we charge, have not been the subject of a protest or a complaint by a shipper. However, FERC could investigate our rates at the urging of a third party if the third party is either a current shipper or has a substantial economic interest in the tariff rate level. Although no assurance can be given that the tariffs charged by us ultimately will be upheld if challenged, management believes that the tariffs now in effect for our pipelines are within the maximum rates allowed under current FERC guidelines.

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We have been approved by FERC to charge market-based rates in most of the refined products locations served by our pipeline systems. In those locations where market-based rates have been approved, we are able to establish rates that are based upon competitive market conditions.

Regulation of Intrastate Crude Oil and Refined Products Pipelines. Some of our crude oil and refined products pipelines are subject to regulation by the Texas R.R.C., the P A PUC, and the OCC. The operations of our joint venture interests are also subject to regulation in the states in which they operate. The applicable state statutes require that pipeline rates be nondiscriminatory and provide no more than a fair return on the aggregate value of the pipeline property used to render services. State commissions generally have not initiated an investigation of rates or practices of petroleum pipelines in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally. Although management cannot be certain that our intrastate rates ultimately would be upheld if challenged, we believe that, given this history, the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.

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 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 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

Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result, there can be no assurance that significant costs and liabilities will not be incurred. 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. Moreover, there can be no assurance that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, will not result in substantial costs and liabilities. We are unable to estimate any losses or range of losses that could result from such developments. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

Our subsidiaries have adopted policies, practices and procedures in the areas of pollution control, product safety, occupational safety and health, and the handling, storage, use, and disposal of hazardous materials to prevent and minimize material environmental or other damage and to limit the financial liability which could result from such events. However, the risk of environmental or other damage is inherent in transporting, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products, as it is with other entities engaged in similar businesses. Environmental exposures and

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liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our subsidiaries' liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future.

The EPA's Spill Prevention, Control and Countermeasures program regulations were recently modified and impose additional requirements on many of our facilities. We expect to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures to comply with the new rules. 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.

On August 20, 2010, the EPA published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines. The rule will require some of our subsidiaries to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment. In response to an industry group legal challenge to portions of the rule in the U.S. Court of Appeals for the D.C. Circuit and a Petition for Administrative Reconsideration to the EPA, on March 9, 2011, the EPA issued a new proposed rule and a direct final rule effective on May 9, 2011 to clarify compliance requirements related to operation and maintenance procedures for continuous parametric monitoring systems. If no further changes to the standard are made as a result of comments to the proposed rule, we would not expect that the cost to comply with the rule's requirements will have a material adverse effect on our financial condition or results of operations. Compliance with the final rule is required by October 2013.

On June 29, 2011, the EPA finalized a rule under the CAA that revised the new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The rule became effective on August 29, 2011. The rule modifications may require some of our subsidiaries to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if equipment is replaced or existing facilities are expanded in the future. At this point, we are not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes our subsidiaries might make in the future, but we would not expect that the cost to comply with the rule's requirements will have a material adverse effect on our financial condition or results of operations.

On April 17, 2012 the EPA issued the Oil and Natural Gas Sector New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants. The standards revise the new source performance standards for volatile organic compounds from leaking components at onshore natural gas processing plants and new source performance standards for sulfur dioxide emissions from natural gas processing plants. The EPA also established standards for certain oil and gas operations not covered by the existing standards. In addition to the operations covered by the existing standards, the newly established standards regulate volatile organic compound emissions from gas wells, centrifugal compressors, reciprocating compressors, pneumatic controllers and storage vessels. ETP is reviewing the new standards to determine the impact on its operations.

Our subsidiaries' pipeline operations are subject to regulation by the 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. 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. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause our subsidiaries to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

Environmental Remediation

Our subsidiaries are responsible for environmental remediation at certain sites, including the following:


•	Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.


•	Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.


•	Southern Union's distribution operations are responsible for soil and groundwater remediation at certain sites related to MGPs and may also be responsible for the removal of old MGP structures.

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To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.

The total accrued future estimated cost of remediation activities relating to ETP’s Transwestern pipeline operations was approximately $6 million as of December 31, 2012, which is included in the aggregate environmental accruals, and such activities are expected to continue through 2025.

The table below reflects the amounts (in millions) of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.



	December 31, 2012		December 31, 2011
Current	$	46	$	4
Non-current	166		10
Total environmental liabilities	$	212	$	14

Employees

As of January 31, 2013, ETE and its consolidated subsidiaries employed an aggregate of 14,433 employees, 2,067 of which are represented by labor unions. We and our subsidiaries believe that our relations with our employees are satisfactory.

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. In addition, those risk factors discussed in ETP's, Southern Union's and Sunoco Logistics' Annual Report on Form 10-K should be considered. The risk factors below, and those included in ETP's, Southern Union's and Sunoco Logistics' Annual Report, are not all the risks we face and other factors currently considered immaterial or unknown to us may impact or future operations.

These are not all the risks we face and other factors currently considered immaterial or unknown to us may impact our future operations.

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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, crude oil and refined products 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 services;


•	the price of natural gas, NGLs, crude oil and refined products;


•	the relationship between natural gas, NGL and crude oil prices;


•	the amount of cash distributions ETP receives with respect to its ownership of AmeriGas common units;


•	the weather in their respective operating areas;


•	the level of competition from other midstream, transportation and storage and retail marketing companies and other energy providers;


•	the level of their respective operating costs;


•	prevailing economic conditions; and


•	the level and results 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 revolving 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.

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Cash distributions are not guaranteed and may fluctuate with our performance or other external factors.

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.

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 may be unable to remove our General Partner. Our General Partner may not be removed except upon the vote of the holders of at least 66²/3% of our outstanding units. Our directors and executive officers directly or indirectly own 69,547,567 Common Units, representing approximately 19% 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.

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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.

ETP’s and Regency’s levels of indebtedness affect their operations in several ways, including, among other things:


•	a significant portion of ETP’s, Regency’s and their subsidiaries' 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, Regency’s and their subsidiaries' existing debt agreements require ETP, Regency and their subsidiaries', as applicable, to meet financial tests that may adversely affect their flexibility in planning for and reacting to changes in their respective businesses;


•	ETP’s, Regency’s and their subsidiaries' ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, 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 by ETP, Regency or their subsidiaries to comply with the various restrictive covenants of the respective 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.

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.

Capital 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 and improvements or repairs to existing facilities that 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

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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. 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.

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.

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.

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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.

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.

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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.

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 17% of ETP’s outstanding Common Units, and Regency GP and its affiliates own approximately 15% 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.

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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.

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, 2012, we owned approximately 50.2 million Common Units of ETP and approximately 26.3 million Common Units of Regency. 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.

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.

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,

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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.


•	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.

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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, 2012, the directors and executive officers of our General Partner owned approximately 19% 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.

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 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

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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.

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.

Income from our midstream, transportation, terminalling and storage operations is exposed to risks due to fluctuations in the demand for and price of natural gas, NGLs and oil that are beyond our control.

The prices for natural gas, NGLs and oil (including refined petroleum products) reflect market demand that fluctuates with changes in global and U.S. economic conditions and other factors, including:


•	the level of domestic natural gas, NGL, and oil production;


•	the level of natural gas, NGL, and oil imports and exports, including liquefied natural gas;


•	actions taken by natural gas and oil producing nations;


•	instability or other events affecting natural gas and oil producing nations;


•	the impact of weather and other events of nature on the demand for natural gas, NGLs and oil;


•	the availability of storage, terminal and transportation systems, and refining, processing and treating facilities;


•	the price, availability and marketing of competitive fuels;


•	the demand for electricity;


•	the cost of capital needed to maintain or increase production levels and to construct and expand facilities


•	the impact of energy conservation and fuel efficiency efforts; and


•	the extent of governmental regulation, taxation, fees and duties.

In the past, the prices of natural gas, NGLs and oil have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2012, the NYMEX natural gas settlement price for the prompt month contract ranged from a high of $3.70 per MMBtu to a low of $2.04 per MMBtu. A composite of the Mont Belvieu average NGLs price based upon our average NGLs composition during our year ended December 31, 2012 ranged from a high of approximately $1.23 per gallon to a low of approximately $0.75 per gallon. Oil spot prices at Cushing, Oklahoma during the year ended December 31, 2012 ranged from a high of approximately $109.39 per barrel to a low of approximately $77.72 per barrel.

Any loss of business from existing customers or our inability to attract new customers due to a decline in demand for natural gas, NGLs, or oil could have a material adverse effect on our revenues and results of operations. In addition, significant price fluctuations for natural gas, NGL and oil commodities could materially affect our profitability

We may be impacted by competition from other midstream, transportation and storage and retail marketing companies.

We experience competition in all of our business segments. With respect to our intrastate transportation and storage segment, our principal areas of competition include obtaining natural gas supplies for the Southeast Texas System, North Texas System and HPL System and natural gas transportation customers for our transportation pipeline systems. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas.

Our natural gas and NGL transportation pipelines and storage facilities compete with other interstate and intrastate pipeline companies and storage providers in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service, access to sources of supply and the flexibility and reliability of service. Natural gas and NGLs

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also competes with other forms of energy, including electricity, coal, fuel oils and renewable or alternative energy. Competition among fuels and energy supplies is primarily based on price; however, non-price factors, including governmental regulation, environmental impacts, efficiency, ease of use and handling, and the availability of subsidies and tax benefits also affects competitive outcomes.

In markets served by our NGL pipelines, we compete with other pipeline companies and barge, rail and truck fleet operations. We also face competition with other storage and fractionation facilities based on fees charged and the ability to receive, distribute and/or fractionate the customer's products.

Our crude oil and refined products pipeline operations face significant competition from other pipelines for large volume shipments. These operations also face competition from trucks for incremental and marginal volumes in areas served by Sunoco Logistics' pipelines. Further, our refined product terminals compete with terminals owned by integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.

We also face strong competition in the market for the sale of retail gasoline and merchandise. Our competitors include service stations operated by fully integrated major oil companies and other well-recognized national or regional retail outlets, often selling gasoline or merchandise at aggressively competitive prices. The actions of our retail marketing competitors, including the impact of foreign imports, could lead to lower prices or reduced margins for the products we sell, which could have an adverse effect on our business or results of operations.

We may be unable to retain or replace existing midstream, transportation, terminalling and storage customers or volumes due to declining demand or increased competition in oil, natural gas and NGL markets, which would reduce our revenues and limit our future profitability.

The retention or replacement of existing customers and the volume of services that we provide at rates sufficient to maintain or increase current revenues and cash flows depends on a number of factors beyond our control, including the price of, and demand for oil, natural gas, and NGLs in the markets we serve and competition from other service providers.

A significant portion of our sales of natural gas are to industrial customers and utilities. As a consequence of the volatility of natural gas prices and increased competition in the industry and other factors, industrial customers, utilities and other gas customers are increasingly reluctant to enter into long-term purchase contracts. Many customers purchase natural gas from more than one supplier and have the ability to change suppliers at any time. Some of these customers 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 us in the marketing of natural gas, we often compete in natural gas sales markets primarily on the basis of price.

We also receive a substantial portion of our revenues by providing natural gas gathering, processing, treating, transportation and storage services. While a substantial portion of our services are sold under long-term contracts for reserved service, we also provide service on an unreserved or short-term basis. Demand for our services may be substantially reduced due to changing market prices. Declining prices may result in lower rates of natural gas production resulting in less use of services; while rising prices may diminish consumer demand and also limit the use of services. In addition, our competitors may attract our customers' business. If demand declines or the effects of competition increases, we may not be able to sustain existing levels of unreserved service or renew or extend long-term contracts as they expire or we may reduce our rates to meet competitive pressures.

Revenue from our NGL transportation systems and refined products storage is also exposed to risks due to fluctuations in demand for transportation and storage service as a result of unfavorable commodity prices, competition from nearby pipelines, and other factors. We receive substantially all of our transportation revenues through dedicated contracts under which the customer agrees to deliver the total output from particular processing plants that are connected only to our transportation system. Reduction in demand for natural gas or NGLs due to unfavorable prices or other factors, however, may result lower rates of production under dedicated contracts and lower demand for our services. In addition, our refined products storage revenues are primarily derived from fixed capacity arrangements between us and our customers, a portion of our revenue is derived from fungible storage and throughput arrangements, under which our revenue is more dependent upon demand for storage from our customers.

The volume of crude oil and refined products transported through our oil pipelines and terminal facilities depends on the availability of attractively priced crude oil and refined products in the areas serviced by our assets. A period of sustained price reductions for crude oil or refined products could lead to a decline in drilling activity, production and refining of crude oil, or import levels in these areas. A period of sustained increases in the price of crude oil or refined products supplied from or delivered to any of these areas could materially reduce demand for crude oil or refined products in these areas. In either case, the volumes of crude oil or refined products transported in our oil pipelines and terminal facilities could decline.

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The loss of existing customers by our midstream, transportation, terminalling and the storage facilities or a reduction in the volume of the services our customers purchase from us, or our inability to attract new customers and service volumes would negatively affect our revenues, be detrimental to our growth, and adversely affect our results of operations.

Our midstream facilities and transportation pipelines are attached to basins with naturally declining production, which we may not be able to replace with new sources of supply.

In order to maintain or increase throughput levels on our gathering systems and transportation pipeline systems and asset utilization rates at our treating and processing plants, we must continually contract for new natural gas supplies and natural gas transportation services.

A substantial portion of our assets, including our gathering systems and our processing and treating plants, are connected to natural gas reserves and wells that experience declining production over time. Our gas transportation pipelines are also dependent upon natural gas production in areas served by our gathering systems or in areas served by other gathering systems or transportation pipelines that connect with our transportation pipelines. We may not be able to obtain additional contracts for natural gas supplies for our natural gas gathering systems, and we may be unable to maintain or increase the levels of natural gas throughput on our transportation pipelines. The primary factors affecting our ability to connect new supplies of natural gas to our gathering systems include our 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 our gathering systems or in areas that provide access to our transportation pipelines or markets to which our systems connect. We have no control over the level of drilling activity in our areas of operation, the amount of reserves underlying the wells and the rate at which production from a well will decline. In addition, we have no control over producers or their production and contracting decisions.

While a substantial portion of our services are provided under long-term contracts for reserved service, we also provide service on an unreserved basis. If the reserves available through the supply basins connected to our gathering, processing, treating, transportation and storage facilities decline and are not replaced by other sources of supply, a decrease in development or production activity could cause a decrease in the volume of unreserved services we provide and decrease in the number and volume of our contracts for reserved transportation service over the long run, and in each case, adversely affect our revenues and results of operations.

If we are unable to replace any significant volume declines with additional volumes from other sources, our results of operations and cash flows could be materially and adversely affected.

As a result of our exit from the refining business, we are entirely dependent upon third parties for the supply of refined products such as gasoline and diesel for our retail marketing business.

As a result of our exit from the refining business, we are required to purchase refined products from third party sources, including the joint venture that acquired our Philadelphia refinery. We may also need to contract for new ships, barges, pipelines or terminals which we have not historically used to transport these products to our markets. The inability to acquire refined products and any required transportation services at prices no less favorable than the formerly applicable market-based transfer prices may adversely affect our business and results of operations.

The profitability of certain activities in our natural gas gathering, processing, 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.

For a portion of the natural gas gathered at our systems, we purchase natural gas from producers at the wellhead and then gather and deliver the natural gas to pipelines where we typically resell the natural gas under various arrangements, including sales at index prices. Generally, the gross margins we realize under these arrangements decrease in periods of low natural gas prices.

We also enter into percent-of-proceeds arrangements, keep-whole arrangements, and processing fee agreements pursuant to which we agree to gather and process natural gas received from the producers.

Under percent-of-proceeds arrangements, we generally sell the residue gas and NGLs at market prices and remit to the producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, we deliver an agreed upon percentage of the residue gas and NGL volumes to the producer and sell the volumes we keep to third parties at market prices. Under these arrangements, our revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have an adverse effect on our revenues and results of operations.

Under keep-whole arrangements, we generally sell the NGLs produced from our gathering and processing operations to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of

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the natural gas, we must either purchase natural gas at market prices for return to producers or make a cash payment to producers equal to the value of this natural gas. Under these arrangements, our revenues and gross margins decrease when the price of natural gas increases relative to the price of NGLs if we are not able to bypass our processing plants and sell the unprocessed natural gas.

When we process the gas for a fee under processing fee agreements, we may guarantee recoveries to the producer. If recoveries are less than those guaranteed to the producer, we may suffer a loss by having to supply liquids or its cash equivalent to keep the producer whole.

We also receive fees and retain gas in kind from our natural gas transportation and storage customers. Our fuel retention fees and the value of gas that we retain in kind are directly affected by changes in natural gas prices. Increases in natural gas prices tend to increase our fuel retention fees and the value of gas we retain, and decreases in natural gas prices tend to decrease our fuel retention fees and the value of retained gas.

In addition, we receive revenue from our off-gas processing and fractionating system in south Louisiana 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 our 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 our off-gas processing and fractionation services and could have an adverse effect on our results of operations.

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 reduce our exposure to fluctuations in 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.

The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are effective economically (whether to mitigate our exposure to fluctuations in commodity prices, or to balance our exposure to fixed and variable interest rates), these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. It is also not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.

In addition, even though monitored by management, our 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 our physical or financial positions or hedging policies and procedures are not followed.

Our natural gas and NGL revenues depend on our customers' ability to use our pipelines and third-party pipelines over which we have no control.

Our natural gas transportation, storage and NGL businesses depend, in part, on our customers' ability to obtain access to pipelines to deliver gas to us and receive gas from us. Many of these pipelines are owned by parties not affiliated with us. Any interruption of service on our pipelines or third party pipelines due to testing, line repair, reduced operating pressures, or other causes or adverse change in terms and conditions of service could have a material adverse effect on our ability, and the ability of our customers, to transport natural gas to and from our pipelines and facilities and a corresponding material adverse effect on our transportation and storage revenues. In addition, the rates charged by interconnected pipelines for transportation to and from our facilities affect the utilization and value of our 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 our storage revenues

Shippers using our oil pipelines and terminals are also dependent upon our pipelines and connections to third-party pipelines to receive and deliver crude oil and refined products. Any interruptions or reduction in the capabilities of these pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes transported in our pipelines or through our terminals. Similarly, if additional shippers begin transporting volume over interconnecting oil pipelines, the allocations of pipeline capacity to our existing shippers on these interconnecting pipelines could be reduced, which also could reduce volumes

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transported in its pipelines or through our terminals. Allocation reductions of this nature are not infrequent and are beyond our control. Any such interruptions or allocation reductions that, individually or in the aggregate, are material or continue for a sustained period of time could have a material adverse effect on our results of operations, financial position, or cash flows.

The inability to continue to access lands owned by third parties, including tribal lands, could adversely affect our ability to operate and adversely affect our financial results.

Our ability to operate our pipeline systems and terminal facilities on certain lands owned by third parties, including lands held in trust by the United States for the benefit of a Native American tribe, will depend on our success in maintaining existing rights-of-way and obtaining new rights-of-way on those lands. Securing extensions of existing and any additional rights-of-way is also critical to our ability to pursue expansion projects. We cannot provide any assurance that we will be able to acquire new rights-of-way or maintain access to existing rights-of-way upon the expiration of the current grants or that all of the rights-of-way will be obtainable in a timely fashion. 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. Our financial position could be adversely affected if the costs of new or extended right-of-way grants cannot be recovered in rates.

Further, whether we have the power of eminent domain for our pipelines varies from state to state, depending upon the type of pipeline and the laws of the particular state. In either case, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. The inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located.

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 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 strategies, managements of ETP and Regency may, from time to time, engage 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 acquisition efforts will be successful or that any 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.

An impairment of goodwill and intangible assets could reduce our earnings.

As of December 31, 2012, our consolidated balance sheets reflected $6.43 billion of goodwill and $2.29 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.

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;

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•	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 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 related 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 and related facilities (or the improvement and repair of existing facilities) involves 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, 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 oil and 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

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in the area to utilize the newly constructed pipelines. In this regard, ETP and Regency may construct facilities to capture anticipated future growth in oil or 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, Regency’s or their joint ventures' 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, Regency or their joint ventures, as applicable, were unable to replace these customers under arrangements that provide similar economic benefits as these existing contracts.

Our interstate pipelines are subject to laws, regulations and policies governing the rates they are allowed to charge for their services, which may prevent us from fully recovering our costs.

Laws, regulations and policies governing interstate natural gas pipeline rates could affect the ability of our 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.

We are required to file tariff rates (also known as recourse rates) with FERC that shippers may elect to pay for interstate natural gas transportation services. We may also agree to discount these rates on a not unduly discriminatory basis or negotiate rates with shippers who elect not to pay the recourse rates. We must also file with FERC all negotiated rates that do not conform to our tariff rates and all changes to our tariff or negotiated rates. FERC must approve or accept all rate filings for us to be allowed to charge such rates.

FERC may review existing tariffs rates own initiative or upon receipt of a complaint filed by a third party. FERC may, on a prospective basis, order refunds of amounts collected if it finds the rates to have been shown not to be just and reasonable or to have been unduly discriminatory. FERC has recently exercised this authority with respect to several other pipeline companies, as it had in 2007 with respect to our Southwest Gas. If FERC were to initiate a proceeding against us and find that our rates were not just and reasonable or unduly discriminatory, the maximum rates customers could elect to pay us may be reduced and the reduction could have an adverse effect on our revenues and results of operations.

The costs of our interstate pipeline operations may increase and we may not be able to recover all of those costs due to FERC regulation of our rates. If we propose to change our tariff rates, our proposed rates may be challenged by FERC or third parties, and FERC may deny, modify or limit our proposed changes if we are unable to persuade FERC that changes would result in just and reasonable rates that are not unduly discriminatory. We also may be limited by the terms of rate case settlement agreements or negotiated rate agreements with individual customers from seeking future rate increases, or we may be constrained by competitive factors from charging our tariff rates.

To the extent our costs increase in an amount greater than our revenues increase, or there is a lag between our cost increases and our ability to file for, and obtain rate increases, our operating results would be negatively affected. Even if a rate increase is permitted by FERC to become effective, the rate increase may not be adequate. We cannot guarantee that our interstate pipelines will be able to recover all of our costs through existing or future rates.

In 2010, in response to an intervention and protest filed by BG LNG Services (BGLS) regarding its rates with Trunkline LNG applicable to certain LNG expansions, FERC determined that there was no reason at that time to expend FERC's resources on a rate proceeding with respect to Trunkline LNG even though cost and revenue studies provided by the Company to FERC indicated Trunkline LNG's revenues were in excess of its associated cost of service. However, since the current fixed rates expire at the end of 2015 and revert to tariff rate for these LNG expansions as well as the base LNG facilities for which rates were set in 2002,

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a rate proceeding could be initiated at that time and result in significant revenue reductions if the cost of service remains lower than revenues.

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 FERC, which was approved by FERC on October 31, 2011. Transwestern is required to file a new general rate case on October 1, 2014. However, shippers that 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 absent shipper complaint.

The ability of interstate pipelines held in tax-pass-through entities, like us, 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 FERC’s policy, we thus remain eligible to include an income tax allowance in the tariff rates we charge for interstate natural gas transportation. The effectiveness of FERC's policy and the application of that policy remains subject to future challenges, refinement or change by FERC or the courts. With regard to rates charged and collected by Transwestern, the allowance for income taxes as a cost-of-service element in our tariff rates is generally not subject to challenge prior to the end of the term of our 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, 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 or must 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, policies and interpretations thereof 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 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 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 FERC for expansions of their pipeline facilities. ETP cannot guarantee that 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. We may also begin to construct a new facility or provide a new service based on a FERC authorization that is subsequently overturned or modified after review by a court. This could have a material adverse effect on the costs of and revenues of the new facility or service

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 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.

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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 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.

Rate regulation or market conditions may not allow us to recover the full amount of increases in the costs of our crude oil and refined products pipeline operations.

Our common carrier interstate crude oil and refined products pipelines are subject to rate regulation by FERC, which requires that tariff rates for these oil pipelines be just and reasonable and not unduly discriminatory. FERC or interested persons may challenge proposed new or changed rates and authorizes FERC to suspend the effectiveness of such rates for up to seven months and to investigate such rates. If, upon completion of an investigation, FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund revenues in excess of the prior tariff during the term of the investigation. FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.

The primary ratemaking methodology used by FERC to authorize increases in the tariff rates of petroleum pipelines is price indexing. If the rate changes allowed under the indexing methodology are not large enough to fully reflect actual increases to our pipeline costs, our financial condition could be adversely affected. If applying the index methodology results in a rate increase that is substantially in excess of our pipeline's actual cost increases, or it results in a rate decrease that is substantially less than our pipeline's actual cost decrease, we may be required to reduce our pipeline rates. FERC's ratemaking methodologies may limit our ability to set rates based on its costs or may delay the use of rates that reflect increased costs. In addition, if FERC's indexing methodology changes, the new methodology could materially and adversely affect our financial condition, results of operations or cash flows.

Under the Energy Policy Act adopted in 1992, certain interstate pipeline rates were deemed just and reasonable or “grandfathered.” Revenues are derived from such grandfathered rates on most of our FERC-regulated pipelines. A person challenging a grandfathered rate must, as a threshold matter, establish a substantial change since the date of enactment of the Energy Policy Act, in either the economic circumstances or the nature of the service that formed the basis for the rate. If FERC were to find a substantial change in circumstances, then the existing rates could be subject to detailed review and there is a risk that some rates could be found to be in excess of levels justified by the pipeline's costs. In such event, FERC could order us to reduce pipeline rates prospectively and to pay refunds to shippers.

If FERC's petroleum pipeline ratemaking methodologies procedures changes, the new methodology or procedures could adversely affect our business and results of operations.

Should we violate laws and regulations prohibiting market manipulation, we could be subject to substantial fines and penalties and lose the governmental authorizations needed conduct our businesses.

The Energy Policy Act of 2005 amended the NGA and NGPA to prohibit fraud and manipulation in natural gas markets. FERC subsequently issued a final rule making it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to FERC's jurisdiction, to defraud, make an untrue statement or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud. FERC is authorized to impose civil penalties of up to $1 million per day per violation and grant other relief, such as ordering refunds, or revoking operating authority.

Wholesale sales of petroleum are subject to provisions of the Energy Independence and Security Act of 2007 (“EISA”) and regulations by the FTC. Under the EISA, the FTC issued a rule that prohibits fraudulent or deceptive conduct (including false or misleading statements of material fact) in connection with wholesale purchases or sales of crude oil or refined petroleum products. The FTC rule also bans intentional failures to state a material fact when the omission makes a statement misleading and distorts, or is likely to distort, market conditions for any product covered by the rule. The FTC holds substantial enforcement authority under the EISA, including authority to request that a court impose fines of up to $1 million per day per violation. FERC may also order reparations and suspend tariffs for violations of the ICA in connection with interstate oil pipeline transportation.

Under the Commodity Exchange Act, the CFTC is directed to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act, the CFTC has adopted anti-market manipulation regulations that prohibit, among other things, fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to assess fines of up to $1,000,000 or triple the monetary gain for violations of its anti-market manipulation regulations.

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State regulatory measures could adversely affect the business and operations of our midstream and intrastate pipeline and storage assets.

Our midstream and intrastate transportation and storage operations are generally exempt from FERC regulation under the NGA, but FERC regulation still significantly affects our business and the market for our products. The rates, terms and conditions of service for the interstate services we provide in our intrastate gas pipelines and gas storage are subject to FERC regulation under Section 311 of the NGPA. Our HPL System, East Texas pipeline, Oasis pipeline and ET Fuel System provide such services. 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 FERC determine not to authorize rates equal to or greater than our costs of service, our cash flow would be negatively affected.

Our midstream and intrastate gas and oil transportation pipelines and our intrastate gas storage operations are subject to state regulation. All of the states in which we operate midstream assets, intrastate pipelines or intrastate storage facilities have adopted some form of complaint-based regulation, which allow producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to the fairness of rates and terms of access. The states in which we operate have ratable take statutes, which generally require gatherers to take, without undue discrimination, 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 our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Should a complaint be filed in any of these states or should regulation become more active, our business may be adversely affected.

Our intrastate transportation operations located in Texas are also subject to regulation as gas utilities by the TRRC. Texas gas utilities must publish the rates they charge for transportation and storage services in tariffs filed with the TRRC, although such rates are deemed just and reasonable under Texas law unless challenged in a complaint.

We are subject to other forms of state regulation, including requirements to obtain operating permits, reporting requirements, and safety rules (see description of federal and state pipeline safety regulation below). Violations state laws, regulations, orders and permit conditions can result in the modification, cancellation or suspension of a permit, civil penalties and other relief.

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 of 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 subject to regulation by FERC, pursuant to the ICA, 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.

We are subject to extensive federal and state pipeline safety regulation, including integrity management requirements, which may adversely affect our costs and operations.

Our pipeline operations are subject to regulation by the DOT, under PHMSA, pursuant to which PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, 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 our current pipeline integrity testing programs, we estimate 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. For the years ended December 31, 2012, 2011 and 2010, $0.0 million, $18.3 million and $13.3 million, respectively, of capital costs and $0.0 million, $14.7 million and $15.4 million, respectively, of operating and maintenance costs have been incurred for pipeline integrity testing. There can be no assurance as to the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could

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cause us to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

Federal pipeline safety regulation is also becoming increasingly stringent and additional laws and regulations are being considered. The recently enacted Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, 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.

On August 13, 2012, PHMSA published rules to update pipeline safety regulations to reflect provisions included in the Pipeline Safety Act of 2011, including increasing maximum civil penalties and changing PHMSA's enforcement process. PHMSA has also published advanced notices of proposed rulemaking to solicit comments on the need for changes to its safety regulations for oil and gas pipelines, including whether to revise the integrity management requirements and add new regulations governing the safety of gathering lines.

Further, additional laws, regulations and policies that may be enacted or adopted in the future or a new interpretation of existing laws and regulations could significantly increase the cost of complying with safety laws and regulations. For example, PHMSA issued an Advisory Bulletin which, among other things, advises pipeline operators that if they are relying on design, construction, inspection, testing or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities to meet the demands of such pressures, could significantly increase our costs or result in reductions of allowable operating pressures, which would reduce available pipeline capacity. Such legislative and regulatory changes could have a material effect on our operations through more stringent and comprehensive safety regulations and higher penalties for the violation of those regulations.

States are largely preempted by federal law from regulating pipeline safety for interstate lines, but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines.

In addition, we are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the Environmental Protection Agency, or EPA, community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and citizens. We are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling points without the benefit of chilling or refrigeration are exempt.

Should we violate federal or state health and safety laws and regulations, we could be subject to substantial criminal, civil and administrative penalties and other relief, as well as potential liabilities to third parties.

Our natural gas distribution operations subject us to risks that could have a material adverse effect on our business, results of operations, cash flows and financial condition.

On December 17, 2012, Southern Union entered into definitive purchase and sale agreements with subsidiaries of the Laclede Group, Inc. to sell the assets of its Missouri Gas Energy and New England Gas Company Divisions. Until the transaction is consummated, we will be subject to various risks relating to our natural gas distribution operations, including the following:


•	our ability to achieve timely and effective rate relief from state regulators;


•	the impact of fluctuations in natural gas prices;


•	the inability to recover from customers certain assets recorded on our balance sheet;


•	adverse weather conditions;


•	operational risks, including accidents, the breakdown or failure of equipment or processes, the failure of suppliers' processing facilities to perform at expected levels of capacity or efficiency and the collision of equipment with facilities; and

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•	catastrophic events, including explosions, fires, earthquakes, floods, landslides, tornadoes, lightning or other similar events.

ETP’s and Regency’s businesses involve hazardous substances and may be adversely affected by environmental regulation.

ETP’s and Regency’s 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 current or former 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 pipelines or 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. Although we have established financial reserves for our estimated environmental remediation liabilities, additional contamination or conditions may be discovered, resulting in increased remediation liabilities. Environmental laws also authorize government agencies, in some circumstance, to seek compensation for natural resource damages as an adjunct to remediation programs. If such natural resource damages claims are brought against us, our liability associated with any such sites could substantially increase. Accordingly, we cannot assure you that our current reserves are adequate to cover all future liabilities, even for currently known contamination.

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.

Product liability claims and litigation could adversely affect our business and results of operations.

Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. There can be no assurance that product liability claims against us would not have a material adverse effect on our business or results of operations.

Along with other refiners, manufacturers and sellers of gasoline, Sunoco is a defendant in numerous lawsuits that allege methyl tertiary butyl ether (“MTBE”) contamination in groundwater. Plaintiffs, who include water purveyors and municipalities responsible for supplying drinking water and private well owners, are seeking compensatory damages (and in some cases injunctive relief, punitive damages and attorneys' fees) for claims relating to the alleged manufacture and distribution of a defective product (MTBE-containing gasoline) that contaminates groundwater, and general allegations of product liability, nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. There has been insufficient information developed about the plaintiffs' legal theories or the facts that would be relevant to an analysis of the ultimate liability to Sunoco. These allegations or other product liability claims against Sunoco could have a material adverse effect on our business or results of 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 April 17, 2012, the EPA issued final rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the 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

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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 by January 2015, which requires the operator to recover rather than 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. These rules will require us to modify certain of our operations, including the possible installation of new equipment. Compliance with such rules will be required within three years of their effective date, and it could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact our business.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas, NGLs, crude oil and refined products that ETP and Regency transport, store or otherwise handle.

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 has recently adopted 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 another which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. In November 2011, the EPA also adopted rules requiring companies with facilities that emit over 25,000 metric tons or more of carbon dioxide to report their greenhouse gas emissions to the EPA by September 30, 2012, a requirement with which we timely complied.

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 may be reduced over time 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, NGLs, crude oil and refined products. 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 fuel 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.

The adoption of the Dodd -Frank Act 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, resulting in our operations becoming more volatile and our cash flows less predictable.

Congress has adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), a comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. This legislation was signed into law by President Obama on July 21, 2010 and requires the U.S. Commodities Futures Trading Commission (the “CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. While certain regulations have been promulgated and are already in effect, the rulemaking and implementation process is still ongoing, and we cannot yet predict the ultimate effect of the rules and regulations on our business.

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The Dodd-Frank Act expanded the types of entities that are required to register with the CFTC and the SEC as a result of their activities in the derivatives markets or otherwise become specifically qualified to enter into derivatives contracts. We will be required to assess our activities in the derivatives markets, and to monitor such activities on an ongoing basis, to ascertain and to identify any potential change in our regulatory status.

Reporting and recordkeeping requirements also could significantly increase operating costs and expose us to penalties for non-compliance. Certain CFTC recordkeeping requirements became effective on October 14, 2010, and additional recordkeeping requirements will be phased in through April 2013. Beginning on December 31, 2012, certain CFTC reporting rules became effective, and additional reporting requirements will be phased in through April 2013. These additional recordkeeping and reporting requirements may require additional compliance resources. Added public transparency as a result of the reporting rules may also have a negative effect on market liquidity which could also negatively impact commodity prices and our ability to hedge.

The CFTC has also issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The CFTC’s position limits rules were to become effective on October 12, 2012, but a United States District Court vacated and remanded the position limits rules to the CFTC. The CFTC has appealed that ruling and it is uncertain at this time whether, when, and to what extent the CFTC's position limits rules will become effective.

The new regulations may also require us to comply with certain margin requirements for our over-the counter derivative contracts with certain CFTC- or SEC-registered entities that could require us to enter into credit support documentation and/or post significant amounts of cash collateral, which could adversely affect our liquidity and ability to use derivatives to hedge our commercial price risk; however, the proposed margin rules are not yet final and therefore 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 also requires that certain derivative instruments be centrally cleared and executed through an exchange or other approved trading platform. Mandatory exchange trading and clearing requirements could result in increased costs in the form of additional margin requirements imposed by clearing organizations. On December 13, 2012, the CFTC published final rules regarding mandatory clearing of certain interest rate swaps and certain index credit default swaps and setting compliance dates for different categories of market participants, the earliest of which is March 11, 2013. The CFTC has not yet proposed any rules requiring the clearing of any other classes of swaps, including physical commodity swaps. Although there may be an exception to the mandatory exchange trading and clearing requirement that applies to our trading activities, we must obtain approval from the board of directors of our General Partner and make certain filings in order to rely on this exception. In addition, mandatory clearing requirements applicable to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging.

Rules promulgated under the Dodd-Frank Act further defined forwards as well as instances where forwards may become swaps. Because the CFTC rules, interpretations, no-action letters, and case law are still developing, it is possible that some arrangements that previously qualified as forwards or energy service contracts may fall in the regulatory category of swaps or options. In addition, the CFTC's rules applicable to trade options may further impose burdens on our ability to conduct our traditional hedging operations and could become subject to CFTC investigations in the future.

The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through restrictions on the types of collateral we are required to post), 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 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. Finally, if we fail to comply with applicable laws, rules or regulations, we may be subject to fines, cease-and-desist orders, civil and criminal penalties or other sanctions.

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

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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 our 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. Some of our facilities are subject to standards and procedures required by the Chemical Facility Anti-Terrorism Standards. We believe we are in compliance with all material requirements; however, such compliance may not prevent a terrorist attack from causing material damage to our facilities or pipelines. Any such 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;


•	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

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•	its ability to successfully integrate acquired businesses and achieve anticipated synergies.

We are subject to risks resulting from the moratorium in 2010 on and the resulting increased costs of offshore deepwater drilling.

The United States Department of Interior (the “DOI”) implemented a six-month moratorium on offshore drilling in water deeper than 500 feet in response to the Macondo accident and oil spill in the U.S. Gulf of Mexico. The offshore drilling moratorium was implemented to permit the DOI to review the safety protocols and procedures used by offshore drilling companies, which review will enable the DOI to recommend enhanced safety and training needs for offshore drilling companies. The moratorium was lifted in October 2010. The United States Bureau of Ocean Energy Management and the Bureau of Safety and Environmental Enforcement (formerly the Bureau of Ocean Energy Management, Regulation and Enforcement) have enacted enhanced regulatory mandates with additional regulatory mandates expected. The new regulatory requirements will increase the cost of offshore drilling and production operations. The increased regulations and cost of drilling operations could result in decreased drilling activity in the areas serviced by Southern Union. Furthermore, the imposed moratorium did result in some offshore drilling companies relocating their offshore drilling operations for currently indeterminable periods of time to regions outside of the United States. Business decisions to not drill in the areas serviced by Southern Union resulting from the increased regulations and costs could result in a reduction in the future development and production of natural gas reserves in the vicinity of Southern Union's facilities, which could adversely affect our business, financial condition, results of operations and cash flows.

Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the petroleum products that we store and transport.

The petroleum products that we store and transport through Sunoco Logistics' operations are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of significant capital. In addition, different product specifications for different markets impact the fungibility of products transported and stored in our pipeline systems and terminal facilities and could require the construction of additional storage to segregate products with different specifications. We may be unable to recover these costs through increased revenues.

In addition, our butane blending services are reliant upon gasoline vapor pressure specifications. Significant changes in such specifications could reduce butane blending opportunities, which would affect our ability to market our butane blending services licenses.

Our business could be affected adversely by union disputes and strikes or work stoppages by Southern Union's and Sunoco's unionized employees.

As of December 31, 2012, approximately 37%, 45% and 7% of Southern Union's, Sunoco Logistics' and Sunoco's workforce, respectively, are covered by a number of collective bargaining agreements with various terms and dates of expirations. There can be no assurances that Southern Union or Sunoco will not experience a work stoppage in the future as a result of labor disagreements. Any work stoppage could, depending on the affected operations and the length of the work stoppage, have a material adverse effect on our business, financial position, results of operations or cash flows.

Governmental regulations and policies, particularly in the areas of taxation, energy and the environment, have a significant impact on our retail marketing business.

Federally mandated standards for use of renewable biofuels, such as ethanol and biodiesel in the production of refined products, are transforming traditional gasoline and diesel markets in North America. These regulatory mandates present production and logistical challenges for both the petroleum refining and ethanol industries, and may require us to incur additional capital expenditures or expenses particularly in our retail marketing business. We may have to enter into arrangements with other parties to meet our obligations to use advanced biofuels, with potentially uncertain supplies of these new fuels. If we are unable to obtain or maintain sufficient quantities of ethanol to support our blending needs, our sale of ethanol blended gasoline could be interrupted or suspended which could result in lower profits. There also will be compliance costs related to these regulations. We may experience a decrease in demand for refined petroleum products due to new federal requirements for increased fleet mileage per gallon or due to replacement of refined petroleum products by renewable fuels. In addition, tax incentives and other subsidies making renewable fuels more competitive with refined petroleum products may reduce refined petroleum product margins and the ability of refined petroleum products to compete with renewable fuels. A structural expansion of production capacity for such renewable biofuels could lead to significant increases in the overall production, and available supply, of gasoline and diesel in markets that we supply. In addition, a significant shift by consumers to more fuel-efficient vehicles or alternative fuel vehicles (such as ethanol or wider adoption of gas/electric hybrid vehicles), or an increase in vehicle fuel economy, whether as a result of technological

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advances by manufacturers, legislation mandating or encouraging higher fuel economy or the use of alternative fuel, or otherwise, also could lead to a decrease in demand, and reduced margins, for the refined petroleum products that we market and sell.

It is possible that any, or a combination, of these occurrences could have a material adverse effect on Sunoco's business or results of operations.

We have outsourced various functions related to our retail marketing business to third-party service providers, which decreases our control over the performance of these functions. Disruptions or delays of our third-party outsourcing partners could result in increased costs, or may adversely affect service levels. Fraudulent activity or misuse of proprietary data involving our outsourcing partners could expose us to additional liability.

Sunoco has previously outsourced various functions related to our retail marketing business to third parties and expects to continue this practice with other functions in the future.

While outsourcing arrangements may lower our cost of operations, they also reduce our direct control over the services rendered. It is uncertain what effect such diminished control will have on the quality or quantity of products delivered or services rendered, on our ability to quickly respond to changing market conditions, or on our ability to ensure compliance with all applicable domestic and foreign laws and regulations. We believe that we conduct appropriate due diligence before entering into agreements with our outsourcing partners. We rely on our outsourcing partners to provide services on a timely and effective basis. Although we continuously monitor the performance of these third parties and maintain contingency plans in case they are unable to perform as agreed, we do not ultimately control the performance of our outsourcing partners. Much of our outsourcing takes place in developing countries and, as a result, may be subject to geopolitical uncertainty. The failure of one or more of our third-party outsourcing partners to provide the expected services on a timely basis at the prices we expect, or as required by contract, due to events such as regional economic, business, environmental or political events, information technology system failures, or military actions, could result in significant disruptions and costs to our operations, which could materially adversely affect our business, financial condition, operating results and cash flow.

Our failure to generate significant cost savings from these outsourcing initiatives could adversely affect our profitability and weaken Sunoco's competitive position. Additionally, if the implementation of our outsourcing initiatives is disruptive to our retail marketing business, we could experience transaction errors, processing inefficiencies, and the loss of sales and customers, which could cause our business and results of operations to suffer.

As a result of these outsourcing initiatives, more third parties are involved in processing our retail marketing information and data. Breaches of security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information or sensitive or confidential data about our retail marketing business or our clients, including the potential loss or disclosure of such information or data as a result of fraud or other forms of deception, could expose us to a risk of loss or misuse of this information, result in litigation and potential liability for us, lead to reputational damage to the Sunoco brand, increase our compliance costs, or otherwise harm our business.

Our operations could be disrupted if our information systems fail, causing increased expenses and loss of sales.

Our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. If a key system was to fail or experience unscheduled downtime for any reason, even if only for a short period, our operations and financial results could be affected adversely. Our systems could be damaged or interrupted by a security breach, fire, flood, power loss, telecommunications failure or similar event. We have a formal disaster recovery plan in place, but this plan may not entirely prevent delays or other complications that could arise from an information systems failure. Our business interruption insurance may not compensate us adequately for losses that may occur.

Security breaches and other disruptions could compromise our information and expose us to liability, which would cause its business and reputation to suffer.

In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personally identifiable information of our employees, in our data centers and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations and business strategy. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties for divulging shipper information, disruption of our operations, damage to our reputation, and loss of confidence in our products and services, which could adversely affect our business.

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The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension fund values, changing demographics and fluctuating actuarial assumptions and may have a material adverse effect on our financial results. In addition, the passage of the Health Care Reform Act in 2010 could significantly increase the cost of providing health care benefits for employees.

Certain of our subsidiaries provide pension plan and other postretirement healthcare benefits to certain of their employees. The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension and other postretirement fund values, changing demographics and fluctuating actuarial assumptions that may have a material adverse effect on the Partnership's future consolidated financial results. In addition, the passage of the Health Care Reform Act of 2010 could significantly increase the cost of health care benefits for our employees. While certain of the costs incurred in providing such pension and other postretirement healthcare benefits are recovered through the rates charged by the Partnership's regulated businesses, the Partnership's subsidiaries may not recover all of the costs and those rates are generally not immediately responsive to current market conditions or funding requirements. Additionally, if the current cost recovery mechanisms are changed or eliminated, the impact of these benefits on operating results could significantly increase.

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.

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, from time to time, members of the U.S. Congress propose and consider substantive changes to the U.S. federal income tax laws that affect the tax treatment of 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.

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Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or 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 Sunoco Logistics depends on its status as a partnership for federal income tax purposes, as well as its not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat Sunoco Logistics as a corporation for federal income tax purposes or if it were to 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 its unitholders.

The anticipated after-tax economic benefit of our investment in the common units of Sunoco Logistics depends largely on Sunoco Logistics being treated as a partnership for federal income tax purposes. Sunoco Logistics has not requested, and does not plan to request, a ruling from the IRS on this matter. The IRS may adopt positions that differ from the ones Sunoco Logistics has taken. A successful IRS contest of the federal income tax positions Sunoco Logistics takes may impact adversely the market for its common units, and the costs of any IRS contest will reduce Sunoco Logistics' cash available for distribution to its unitholders. If Sunoco Logistics were to be treated as a corporation for federal income tax purposes, it would pay federal income tax at the corporate tax rate, and likely would pay state income tax at varying rates. Distributions to its unitholders generally would be subject to tax again as corporate distributions. Treatment of Sunoco Logistics as a corporation would result in a material reduction in its anticipated cash flow and after-tax return to its unitholders. Current law may change so as to cause Sunoco Logistics to be treated as a corporation for federal income tax purposes or to otherwise subject it to a material amount of entity-level taxation. 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 states were to impose a tax on Sunoco Logistics, the cash available for distribution to its unitholders would be reduced.

As discussed above, the present federal income tax treatment of publicly traded partnerships, including Sunoco Logistics, or our investment in its common units, may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Moreover, any such modification could make it more difficult or impossible for Sunoco Logistics to meet the exception which allows publicly traded partnerships that generate qualifying income to be treated as partnerships (rather than corporations) for U.S. federal income tax purposes, affect or cause Sunoco Logistics to change its business activities, or affect the tax consequences of our investment in Sunoco Logistics' common units. Any such changes could negatively impact the value of our investment in Sunoco Logistics' common units.

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 that 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

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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 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.

We have subsidiaries that will be treated as corporations for federal income tax purposes and subject to corporate-level income taxes.

Even though we (as a partnership for U.S. federal income tax purposes) are not subject to U.S. federal income tax, some of our operations are currently, and our acquisition of Sunoco and the Holdco restructuring resulted in an increase in the proportion of our operations that are conducted through subsidiaries that are organized as corporations for U.S. federal income tax purposes. The taxable income, if any, of subsidiaries that are treated as corporations for U.S. federal income tax purposes, is subject to corporate-level U.S. federal income taxes, which may reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS or other state or local jurisdictions were to successfully assert that these corporations have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, the cash available for distribution could be further reduced. The income tax return filings positions taken by these corporate subsidiaries require significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is also required in assessing the timing and amounts of deductible and taxable items. Despite our belief that the income tax return positions taken by these subsidiaries are fully supportable, certain positions may be successfully challenged by the IRS, state or local jurisdictions.

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.

Because we cannot match transferors and transferees of Common Units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our Unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of Common Units and could have a negative impact on the value of our Common Units or result in audit adjustments to tax returns of our Unitholders. Moreover, because we have subsidiaries that are organized as C corporations for federal income tax purposes owns units in us, 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.

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

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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 (and our Unitholders could receive two Schedules K-1 if relief was not available, as described below) 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 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. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

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 many states, most of which 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.

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ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

A description of our properties is included in “Item 1. Business.” We and our subsidiaries own an executive office building in Dallas, Texas and office buildings in Houston and San Antonio, 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 our subsidiaries’ 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. Our subsidiaries 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

Sunoco, along with other refiners, manufacturers and sellers of gasoline, is a defendant in lawsuits alleging MTBE contamination of groundwater. The plaintiffs typically include water purveyors and municipalities responsible for supplying drinking water and governmental authorities. The plaintiffs are asserting primarily product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. The plaintiffs in all of the cases are seeking to recover compensatory damages, and in some cases, injunctive relief, punitive damages and attorneys' fees.

As of December 31, 2012, Sunoco was a defendant in two lawsuits involving one state and Puerto Rico. These cases are venued in a multidistrict proceeding in a New York federal court. Both cases assert natural resource damage claims. In addition, Sunoco has received notice from another state that it intends to file an MTBE lawsuit in the near future asserting natural resource damage claims.

Discovery is proceeding in these cases. There has been insufficient information developed about the plaintiffs' legal theories or the facts in the natural resource damage claims that would be relevant to an analysis of the ultimate liability of Sunoco in these matters; however, it is reasonably possible that a loss may be realized. Management believes that the MBTE cases could have a significant impact on results of operations for any future period, but does not believe that the cases will have a material adverse effect on its consolidated financial position.

For a description of legal proceedings, see Note 11 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		Cash Distribution⁽¹⁾
Fiscal Year 2012:
Fourth Quarter	$	48.20	$	41.72	$	0.635
Third Quarter	46.07		39.91		0.625
Second Quarter	43.12		34.00		0.625
First Quarter	44.47		38.86		0.625
Fiscal Year 2011:
Fourth Quarter	$	42.00	$	30.78	$	0.625
Third Quarter	45.42		33.21		0.625
Second Quarter	47.34		38.77		0.625
First Quarter	45.47		37.27		0.560


⁽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.

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 January 31, 2013, there were approximately 156,134 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, 2012, common units represent an aggregate 99.75% limited partner interest in us. Our General Partner owns an aggregate 0.25% 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.

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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 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

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 millions.

In October 2012, ETP sold ETC Canyon Pipeline, LLC ("ETC Canyon") for approximately $207 million. The results of continuing operations of Canyon have been reclassified to loss from continuing operations and the prior year amounts have been adjusted to present Canyon's operations as discontinued operations.

In December 2012, Southern Union entered into a purchase and sale agreement with the Laclede Entities, pursuant to which Laclede Missouri has agreed to acquire the assets of Missouri Gas Energy division and Laclede Massachusetts has agreed to acquire the assets of the New England Gas Company division. For the period from our acquisition of Southern Union (March 26, 2012) to December 31, 2012 the results of operations of distribution operations have been adjusted to income from discontinued operations.



	Years Ended December 31,
Statement of Operations Data:	2012		2011		2010		2009		2008
Total revenues	$	16,964	$	8,190	$	6,556	$	5,378	$	9,236
Operating income	1,360		1,237		1,044		1,047		1,079
Income from continuing operations	1,383		531		345		692		675
Basic income from continuing operations per limited partner unit	1.17		1.39		0.87		1.97		1.67
Diluted income from continuing operations per limited partner unit	1.17		1.38		0.87		1.97		1.67
Cash distribution per unit	2.51		2.44		2.16		2.14		1.91
Balance Sheet Data (at period end):
Total assets	48,904		20,897		17,379		12,161		11,070
Long-term debt, less current maturities	21,440		10,947		9,346		7,751		7,190
Total equity	16,350		7,388		6,248		3,220		2,339

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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.

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. In addition, we own a 60% interest in Holdco, as described below.

At December 31, 2012, our equity interests consisted of:



	General Partner Interest (as a % of total partnership interest)		Incentive Distribution Rights (“IDRs”)		Limited Partner Units
ETP	0.9	%	100	%	50,226,967
Regency	1.6	%	100	%	26,266,791

The Parent Company’s principal sources of cash flow have historically derived from its direct and indirect investments in the 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. Effective with the acquisition of Southern Union in March 2012, the Parent Company also generated cash flows through its wholly-owned subsidiary, Southern Union until its contribution of Southern Union to Holdco on October 5, 2012. Subsequent to October 5, 2012, we also generate cash flows from our direct investment in Holdco. 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 subsidiaries.

As a result of the Regency Transactions in May 2010, the Southern Union Merger in March 2012 and the Holdco Transaction in October 2012, the periods presented herein do not include activities from Regency, Southern Union or Sunoco prior to the consummation of the respective mergers and/or transactions.

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, 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.

Subsequent to the Holdco Transaction on October 5, 2012, as described above, our reportable segments changed. Our reportable segments currently consist of the following:


•	Reportable segments of ETP:


◦	Natural gas operations, including the following:

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◦	natural gas midstream and intrastate transportation and storage through Southern Union and La Grange Acquisition, L.P., which conducts business under the assumed name of ETC OLP; and


◦	interstate natural gas transportation and storage through ET Interstate and Southern Union. ET Interstate is the parent company of Transwestern, ETC FEP, ETC Tiger and CrossCountry. Southern Union is the parent company of Panhandle, which provides transportation and storage services through the Panhandle, Trunkline and Sea Robin transmission systems.


◦	NGL transportation, storage and fractionation services primarily through Lone Star.


◦	Refined product and crude oil operations, including the following:


◦	refined product and crude oil transportation through Sunoco Logistics; and


◦	retail marketing of gasoline and middle distillates through Sunoco.


•	Investment in Regency, including the consolidated operations of Regency.


•	Corporate and Other, including the following:


◦	activities of the Parent Company;


◦	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.; and


◦	ETP's corporate and other, which includes the following operating segments that do not meet the qualitative threshold for separate reporting:


▪	natural gas compression services through ETC Compression;


▪	a limited partner interest in AmeriGas;


▪	a non-operating interest in PES;


▪	natural gas distribution operations through Southern Union; and


▪	approximately 30% non-operating interest in a refining joint venture.

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. ETP also controls Holdco.

Recent Developments

On January 12, 2012, ETP Contributed its propane operations, consisting of HOLP and Titan (collectively, the “Propane Business”) to AmeriGas. ETP received approximately $1.46 billion in cash and approximately 29.6 million AmeriGas common units. AmeriGas assumed approximately $71 million of existing HOLP debt. In connection with the closing of this transaction, ETP entered into a support agreement with AmeriGas pursuant to which ETP is obligated to provide contingent, residual support of $1.5 billion of intercompany indebtedness owed by AmeriGas to a finance subsidiary that in turn supports the repayment of $1.5 billion of senior notes issued by this AmeriGas finance subsidiary to finance the cash portion of the purchase price.

On October 5, 2012, ETP completed its merger with Sunoco. Under the terms of the merger agreement, Sunoco shareholders received a total of approximately 55 million ETP Common Units and approximately $2.6 billion in cash.

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an agreement with Algonquin Power & Utilities Corp (APUC") that will allow a subsidiary of APUC to assume the right of the Laclede Entities to purchase the assets of Southern Union's New England Gas Company division, subject to certain approvals. It is expected that the transactions contemplated by the Purchase and Sale Agreements will close by the end of the third quarter of 2013.

As we and our subsidiaries have completed several major strategic transactions since 2011 to expand our midstream service capabilities and to geographically diversity our asset platform, our focus is currently on the full integration and optimization of our diversified asset portfolio to enhance unitholder value. We expect to simplify our organization during 2013 and 2014 and possibly beyond. In order to take advantage of numerous asset optimization opportunities, we may consider potential transactions among us and our subsidiaries and/or affiliates.

In addition, we expect to benefit from continued growth among our existing consolidated subsidiaries. Aggregate growth capital expenditures among our consolidated subsidiaries totaled $3.52 billion in 2012, and we expect that amount to be between $2.06 billion and $2.36 billion in 2013. Our announced growth projects include a second fractionator at Mont Belvieu and expansion in the Eagle Ford Shale and Permian Basin. Along with the inherent benefits of greater scale and cash flow diversification that we experience from growth projects, we also expect to benefit in 2013 from the full-year impacts of the recent Southern Union and Sunoco acquisitions as well as additional synergies that may be created as we continue to streamline the organization.

Results of Operations

Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011 (tabular dollar amounts are expressed in millions)

We previously reported net income as a measure of segment performance. We have revised certain reports provided to our chief operating decision maker to assess the performance of our business to reflect Segment Adjusted EBITDA. We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, loss on extinguishment of debt, gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership's proportionate ownership and amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries' results of operations.

Based on the change in our segment performance measure, we have adjusted the presentation of our segment results for the prior years to be consistent with the current year presentation.

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Consolidated Results



	Years Ended December 31,
	2012			2011			Change
Segment Adjusted EBITDA:
Intrastate Transportation	$	601		$	667		$	(66	)
Interstate Transportation and Storage	1,013			373			640
Midstream	438			389			49
NGL Transportation and Services	209			127			82
Retail Marketing	109			—			109
Investment in Sunoco Logistics	219			—			219
Investment in Regency	480			422			58
Corporate and Other	36			153			(117		)
Total	3,105			2,131			974
Depreciation and amortization	(871		)	(586		)	(285		)
Interest expense, net of interest capitalized	(1,018		)	(740		)	(278		)
Bridge loan related fees	(62		)	—			(62		)
Gain on deconsolidation of Propane Business	1,057			—			1,057
Losses on non-hedged interest rate derivatives	(19		)	(78		)	59
Non-cash unit-based compensation expense	(47		)	(42		)	(5		)
Unrealized gains on commodity risk management activities	10			7			3
LIFO valuation reserve	(75		)	—			(75		)
Losses on extinguishments of debt	(123		)	—			(123		)
Proportionate share of unconsolidated affiliates' interest, depreciation, amortization, non-cash compensation expense, loss on extinguishment of debt and taxes	(435		)	(114		)	(321		)
Adjusted EBITDA related to discontinued operations	(99		)	(23		)	(76		)
Other, net	14			(7		)	21
Income from continuing operations before income tax expense	1,437			548			889
Income tax expense	54			17			37
Income from continuing operations	1,383			531			852
Loss from discontinued operations	(109		)	(3		)	(106		)
Net income	$	1,274		$	528		$	746

See the detailed discussion of Segment Adjusted EBITDA in the Segment Operating Results section below.

Depreciation and Amortization. Depreciation and amortization increased primarily due to the following:


•	depreciation and amortization related to Southern Union of $179 million from March 26, 2012 to December 31, 2012;


•	depreciation and amortization related to Sunoco Logistics and Sunoco of $63 million and $32 million, respectively, from October 5, 2012 through December 31, 2012; and


•	additional depreciation and amortization recorded from assets placed in service in 2012 and 2011; partially offset by


•	the deconsolidation of ETP's Propane Business in January 2012, which had recognized depreciation of $4 million and $82 million for years ended December 31, 2012 and 2011.

Interest Expense, Net of Interest Capitalized. Interest expense increased primarily due to the following:


•	interest expense of $130 million recorded by Southern Union from March 26, 2012 through December 31, 2012;

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•	interest expense of $14 million and $9 million recorded by Sunoco Logistics and Sunoco, respectively, from October 5, 2012 to December 31, 2012;


•	incremental interest expense recorded by ETP primarily due to the issuance of $1.5 billion of senior notes in May 2011 and $2.0 billion of notes in January 2012 to fund acquisitions; and


•	an increase of $71 million for the Parent Company primarily related to the Parent Company's $2.0 billion Senior Secured Term Loan which was used to fund a portion of the cash consideration for the Southern Union Merger; partially offset by


•	a reduction of interest due to ETP's repurchase of $750 million of its senior notes in January 2012.

Gain on Deconsolidation of Propane Business. ETP recognized a gain on deconsolidation related to the contribution of its Propane Business to AmeriGas in January 2012.

Losses on Non-Hedged Interest Rate Derivatives. Losses on non-hedged interest rate derivatives decreased due to the recognition of losses in 2011 resulting from significant forward rate decreases during 2011.

LIFO Valuation Reserve. A LIFO valuation reserve was recorded for the inventory associated with Sunoco's retail marketing operations as a result of commodity price changes subsequent to the inventory being recorded at fair value in connection with purchase accounting.

Unrealized Gains (Losses) on Commodity Risk Management Activities. See additional discussion of the unrealized gains (losses) on commodity risk management activities included in the discussion of segment results below.

Losses on Extinguishments of Debt. ETP recognized a loss on extinguishment of debt for the year ended December 31, 2012 in connection with its repurchase of approximately $750 million in aggregate principal amount of senior notes in January 2012.

Proportionate Share of Unconsolidated Affiliates' Interest, Depreciation, Amortization, Non-cash Compensation Expense, Loss on Debt Extinguishment and Taxes. Amounts reflected for 2012 primarily include our proportionate share of such amounts related to AmeriGas, Citrus, FEP, HPC and MEP. The 2011 amounts primarily represented our proportionate share of such amounts and do not include AmeriGas and Citrus.

Adjusted EBITDA Attributable to Discontinued Operations. Amounts reflect the operations of Canyon, which was sold in October 2012, and, for the period from March 26, 2012 to December 31, 2012, Southern Union's distribution operations.

Other, net. Other, net increased in 2012 primarily due to Southern Union's recognition of a net curtailment gain of $15 million related to its postretirement benefit plans.

Income Tax Expense. The increase in income tax expense for the year ended December 31, 2012 compared to the same periods last year were primarily due to our acquisition of Southern Union in March 2012 which has a higher overall effective rate as Southern Union is subject to federal and state income taxes.

Supplemental Pro Forma Financial Information

The following unaudited pro forma consolidated financial information of ETP has been prepared in accordance with Article 11 of Regulation S-X and reflects the pro forma impacts of the Sunoco Merger and Holdco Transaction for the year ended December 31, 2012 and 2011, giving effect that each occurred on January 1, 2011. This unaudited pro forma financial information is provided to supplement the discussion and analysis of the historical financial information and should be read in conjunction with such historical financial information. This unaudited pro forma information is for illustrative purposes only and is not necessarily indicative of the financial results that would have occurred if the Sunoco Merger and Holdco Transaction had been consummated on January 1, 2011.

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The following table presents the pro forma financial information for the year ended December 31, 2012:



	ETE Historical			Propane Transaction			(a)	Sunoco Historical			(b)	Southern Union Historical			(c)	Holdco Pro Forma Adjustments			(d)	Pro Forma
REVENUES	$	16,964		$	(93	)		$	35,258			$	443			$	(12,174	)		$	40,398
COSTS AND EXPENSES:
Cost of products sold - natural gas operations	14,153			(80		)		33,142				302				(11,193		)		36,324
Depreciation and amortization	871			(4		)		168				49				76				1,160
Selling, general and administrative	580			(1		)		459				11				(119		)		930
Impairment charges	—							124								(22		)		102
Total costs and expenses	15,604			(85		)		33,893				362				(11,258		)		38,516
OPERATING INCOME	1,360			(8		)		1,365				81				(916		)		1,882
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(1,080		)	(24		)		(123		)		(50		)		2				(1,275		)
Equity in earnings of affiliates	212			19				41				16				5				293
Gain on deconsolidation of Propane Business	1,057			(1,057		)		—				—				—				—
Gain on formation of Philadelphia Energy Solutions	—			—				1,144				—				(1,144		)		—
Loss on extinguishment of debt	(123		)	115				—				—				—				(8		)
Gains (losses) on non-hedged interest rate derivatives	(19		)	—				—				—				—				(19		)
Impairment charges	—			—				—				—				—				—
Other, net	30			2				118				(2		)		(2		)		146
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT)	1,437			(953		)		2,545				45				(2,055		)		1,019
Income tax expense (benefit)	54