Form 10-K
Table of Contents
Index to Financial Statements

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

 

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

For the fiscal year ended December 31, 2009

OR

 

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

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 and 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   Ö    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   Ö  

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   Ö     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         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   Ö      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   Ö  

The aggregate market value as of June 30, 2009, of the registrant’s Common Units held by non-affiliates of the registrant, based on the reported closing price of such units on the New York Stock Exchange on such date, was $2.88 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 16, 2010, the registrant had 222,941,172 Common Units outstanding.


Table of Contents
Index to Financial Statements

TABLE OF CONTENTS

 

PART I
         PAGE

ITEM 1.

 

BUSINESS

   2

ITEM 1A.

 

RISK FACTORS

   26

ITEM 1B.

 

UNRESOLVED STAFF COMMENTS

   59

ITEM 2.

 

PROPERTIES

   60

ITEM 3.

 

LEGAL PROCEEDINGS

   61

ITEM 4.

 

[RESERVED]

  

PART II

ITEM 5.

 

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

   62

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

   111

ITEM 9.

 

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

   186

ITEM 9A.

 

CONTROLS AND PROCEDURES

   186

ITEM 9B.

 

OTHER INFORMATION

   188

PART III

ITEM 10.

 

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

   188

ITEM 11.

 

EXECUTIVE COMPENSATION

   194

ITEM 12.

 

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

   210

ITEM 13.

 

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

   212

ITEM 14.

 

PRINCIPAL ACCOUNTING FEES AND SERVICES

   213

PART IV

ITEM 15.

 

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

   215

 

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Index to Financial Statements

PART I

Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by us in periodic press releases and some oral statements of our officials during presentations about us, include certain “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”). 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,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may,” “will,” or similar expressions help identify forward-looking statements. Although we and our general partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, neither we nor our general partner can give assurances that such expectations 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, our actual results may vary materially from those anticipated, estimated, projected or expected. When considering forward-looking statements, please read the section titled “Risk Factors” included under Item 1A of 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

Btu

   British thermal unit, an energy measurement

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.

Dth

   million British thermal units (“dekatherm”). A therm factor is used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used.

Mcf

   thousand cubic feet

MMBtu

   million British thermal units

MMcf

   million cubic feet

Bcf

   billion cubic feet

NGL

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

Tcf

   trillion cubic feet

LIBOR

   London Interbank Offered Rate

NYMEX

   New York Mercantile Exchange

Reservoir

   a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

 

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ITEM 1.  BUSINESS

Overview

We are a publicly traded Delaware limited partnership, formerly known as La Grange Energy, L.P. Our Common Units are publicly traded on the New York Stock Exchange (“NYSE”) under the ticker symbol “ETE.” We were formed in September 2002 and completed our initial public offering of 24,150,000 Common Units in February 2006.

Unless the context requires otherwise, references to “we,” “us,” “our,” and “ETE” shall mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. (“ETP”), Energy Transfer Partners G.P., L.P (“ETP GP”), the general partner of ETP, and ETP GP’s general partner, Energy Transfer Partners, L.L.C. (“ETP LLC”). References to the “Parent Company” shall mean Energy Transfer Equity, L.P. on a stand-alone basis.

The Parent Company’s only cash generating assets are its direct and indirect investments in limited partner and general partner interests in ETP. The Parent Company’s direct and indirect ownership of ETP consist of approximately 62.5 million Common Units, the general partner interests in ETP and 100% of the Incentive Distribution Rights in ETP. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of ETP or the Operating Companies.

Currently, the Parent Company’s business operations are conducted only through ETP’s wholly-owned operating subsidiaries (collectively referred to as the “Operating Companies”). The activities in which we are engaged, all of which are in the United States, and the Operating Companies through which we conduct those activities are as follows:

 

Ÿ  

Natural gas operations, consisting of the following segments:

 

  ¡  

natural gas midstream and intrastate transportation and storage through La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company (“ETC OLP”);

 

  ¡  

interstate natural gas transportation services through Energy Transfer Interstate Holdings, LLC (“ET Interstate”), ETC Fayetteville Express Pipeline, LLC (“ETC FEP”) and ETC Tiger Pipeline, LLC (“ETC Tiger”). ET Interstate is the parent company of Transwestern Pipeline Company, LLC (“Transwestern”) and ETC Midcontinent Express Pipeline, LLC (“ETC MEP”).

 

Ÿ  

Retail propane through Heritage Operating, L.P. (“HOLP”) and Titan Energy Partners, L.P. (“Titan”).

In order to fully understand the financial condition and results of operations of the Parent Company on a stand-alone basis, we have included herein discussions of Parent Company matters apart from those of our consolidated group.

Significant Achievements in 2009 and Beyond

Our significant 2009 achievements included the following, as discussed in more detail herein:

 

Ÿ  

Distributions to the Parent Company from ETP for 2009 were $223.4 million, $19.5 million and $350.5 million related to its limited partner interests, general partner interests and Incentive Distribution Rights, respectively.

 

Ÿ  

On a consolidated basis, we had revenues of approximately $5.42 billion, operating income of approximately $1.11 billion and net income of approximately $697.9 million. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

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Ÿ  

Continued our expansion initiative, completing projects totaling more than 1,000 miles of large diameter pipeline ranging from 36 inches to 42 inches with approximately 5 Bcf/d of natural gas transportation capacity during 2009. These pipeline completions, coupled with our existing pipeline systems, further enhance our natural gas transportation capabilities to and from the most prolific producing areas in the United States of America. Below is information about some of our more significant completed expansion projects.

 

Project

   Capacity    Miles    Completion Date

36” Southern Shale

   700 MMcf/d    31    January 2009

36” Cleburne to Tolar

   400 MMcf/d    20    January 2009

36” Katy expansion

   400 MMcf/d    56    February 2009

Phoenix lateral

   500 MMcf/d    260    February 2009

42” Texas Independence Pipeline

   1.1 Bcf/d    143    August 2009

 

Ÿ  

Completed construction of the Midcontinent Express pipeline, an approximately 500-mile interstate natural gas pipeline that originates near Bennington, Oklahoma, is routed through Perryville, Louisiana, and terminates at an interconnect with Transcontinental Gas Pipeline Corporation’s, or Transco’s, interstate natural gas pipeline in Butler, Alabama. The pipeline has a current capacity of 1.4 Bcf/d on Zone 1 and 1.0 Bcf/d on Zone 2, all of which has been committed pursuant to predominantly 10-year firm transportation contracts with shippers. The pipeline has also received long-term transportation contracts related to additional capacity that is planned to be added through the utilization of additional compression. The planned capacity expansions to 1.8 Bcf/d on Zone 1 and 1.2 Bcf/d on Zone 2 are expected to completed in the latter part of 2010. Midcontinent Express pipeline is a 50/50 joint venture with Kinder Morgan Energy Partners, L.P. (“KMP”).

 

Ÿ  

Completed several financing transactions despite challenging market conditions, including:

 

  ¡  

The issuance of $1.0 billion aggregate principal amount of Senior Notes by ETP in April 2009.

 

  ¡  

The issuance of an aggregate of 23,575,000 ETP Common Units from offerings in January 2009, April 2009 and October 2009.

 

  ¡  

The issuance of 1,891,691 ETP Common Units during November and December 2009 under an equity distribution program, as described in Note 7 to our consolidated financial statements.

 

  ¡  

The issuance of $350.0 million aggregate principal amount of Senior Notes at Transwestern in December 2009.

In addition, in January 2010, ETP issued 9,775,000 ETP Common Units through a public offering. The proceeds from these transactions were used primarily to repay borrowings under our revolving credit facility and to fund capital expenditures related to pipeline projects.

Recent Developments and Current Growth Projects

Fayetteville Express Pipeline LLC

In October 2008, ETP entered into a 50/50 joint venture with KMP for the development of the Fayetteville Express pipeline, an approximately 185-mile 42 inch pipeline that will originate in Conway County, Arkansas, continue eastward through White County, Arkansas and terminate at an interconnect with Trunkline Gas Company in Quitman County, Mississippi. The pipeline is expected to have an initial capacity of 2.0 Bcf/d. In December 2009, Fayetteville Express Pipeline LLC (“FEP”), the entity formed to own and operate this pipeline,

 

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received approval of its application for Federal Energy Regulatory Commission (“FERC”) authority to construct and operate this pipeline. The only request for rehearing of FERC’s authorization is a limited one related to a discrete rate issue filed by FEP itself. Subject to final resolution of this issue, the pipeline is expected to be in service by the end of 2010. FEP has secured binding 10-year commitments for transportation of approximately 1.85 Bcf/d. The new pipeline will interconnect with Natural Gas Pipeline Company of America (“NGPL”) in White County, Arkansas, Texas Gas Transmission in Coahoma County, Mississippi, and ANR Pipeline Company in Quitman County, Mississippi. NGPL is operated and partially owned by Kinder Morgan, Inc., which owns the general partner of KMP. Our estimate of the total costs of this project is approximately $1.2 billion.

Tiger Pipeline

In January 2009, ETP announced that we had entered into an agreement with Chesapeake Energy Marketing, Inc., a wholly-owned subsidiary of Chesapeake Energy Corporation (“Chesapeake”), to construct an approximately 180-mile 42-inch interstate natural gas pipeline (“Tiger pipeline”). Tiger pipeline will connect to ETP’s dual 42-inch pipeline system near Carthage, Texas, extend through the heart of the Haynesville Shale and end near Delhi, Louisiana, with interconnects to at least seven interstate pipelines at various points in Louisiana.

The agreement with Chesapeake provides for a 15-year commitment for firm transportation capacity of approximately 1.0 Bcf/d. ETP has also entered into agreements with EnCana Marketing (USA), Inc., a subsidiary of EnCana Corporation and other shippers that provide for 10-year commitments for firm transportation capacity on the Tiger pipeline, bringing the initial design capacity to 2.0 Bcf/d in the aggregate, which is expected to be in service in the first half of 2011. In February 2010, we announced that we had entered into a 10-year commitment for an additional 400 MMcf/d. The ultimate capacity of the expansion, which is expected to be completed in the second half of 2011, will be based on producer response during a binding open season.

In August 2009, ETP filed an application for FERC authority to construct and operate the Tiger pipeline, which is pending necessary regulatory approvals. We expect the total costs of this project to be $1.2 billion, excluding the costs of the recently announced expansion. The ultimate cost will depend on the results of the binding open season.

ETP Operations

Segment Overview

Our segments and business are as described below. See Note 15 to our consolidated financial statements for additional financial information about our segments.

Intrastate Transportation and Storage Segment

Through our intrastate transportation and storage segment, we own and operate approximately 7,800 miles of natural gas transportation pipelines and three natural gas storage facilities located in the state of Texas.

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 between major markets from various 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 are referred to as the ET Fuel System, and our HPL System, which are described below.

Our intrastate transportation and storage segment accounted for approximately 56%, 65% and 59% of our total consolidated operating income for the years ended December 31, 2009, December 31, 2008 and August 31, 2007, respectively. The results from our intrastate transportation and storage segment are primarily derived from the

 

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Index to Financial Statements

fees we charge to transport natural gas on our pipelines, including a fuel retention component. 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 the 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 purchased at a discount to a specified market price and 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.

Interstate Transportation Segment

Through our interstate transportation segment, we own and operate approximately 2,700 miles of interstate natural gas pipeline, with an additional 180 miles under construction. In addition, we have interests in joint ventures that have 500 miles of interstate natural gas pipeline and 185 miles under construction.

Our interstate transportation segment accounted for approximately 12%, 11% and 12% of our total consolidated operating income for the years ended December 31, 2009, December 31, 2008 and August 31, 2007, respectively. The results from our interstate transportation segment are primarily derived from the fees earned from natural gas transportation services and operational gas sales. In addition, our joint ventures contributed $17.6 million of our income before income taxes for the year ended December 31, 2009.

Midstream Segment

Through our midstream segment, we own and operate approximately 7,000 miles of in service natural gas gathering pipelines, three natural gas processing plants, eleven natural gas treating facilities and eleven 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 the Austin Chalk trend of southeast Texas, the Permian Basin of west Texas and New Mexico, the Barnett Shale in north Texas, the Bossier Sands in east Texas, and the Uinta and Piceance Basins in Utah and Colorado and are integrated with our intrastate transportation and storage assets.

Our midstream segment accounted for approximately 12%, 14% and 15% of our total consolidated operating income for the years ended December 31, 2009, December 31, 2008 and August 31, 2007, respectively. Our midstream segment results are derived primarily from margins we realize for natural gas volumes that are gathered, transported, purchased and sold through our pipeline systems, processed at our processing and treating facilities, and the volumes of NGLs processed at our 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. See Item 7A, “Quantitative and Qualitative Disclosures about Market Risk”.

Retail Propane Segment

We are one of the three largest retail propane marketers in the United States based on gallons sold and serve more than one million customers through a nationwide retail distribution network consisting of approximately 440 customer service locations in approximately 40 states. Our propane operations extend from coast to coast with concentrations in the western, upper midwestern, northeastern and southeastern regions of the United States. Our propane business has grown primarily through acquisitions of retail propane operations and, to a lesser extent, through internal growth.

Our retail propane segment accounted for approximately 21%, 10% and 15% of our total consolidated operating income for the years ended December 31, 2009, December 31, 2008 and August 31, 2007, respectively. The retail propane segment is a margin-based business in which gross profits depend on the excess of sales price over

 

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Index to Financial Statements

propane supply cost. Consequently, the profitability of our retail propane business is sensitive to changes in wholesale propane prices. Our propane business is largely seasonal and dependent upon weather conditions in our service areas, as discussed further in “Retail Propane Segment-Industry Overview.”

Natural Gas Operations – Asset Overview

The following map depicts the major components of our natural gas operations:

LOGO

Intrastate Transportation and Storage Segment

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

ET Fuel System

 

Ÿ  

Capacity of 5.2 Bcf/d

Ÿ  

Approximately 2,570 miles of natural gas pipeline

Ÿ  

2 storage facilities with 12.4 Bcf of total working gas capacity

The ET Fuel System serves some of the most active drilling areas in the United States, and is comprised of approximately 2,570 miles of intrastate natural gas pipeline and related natural gas storage facilities. Included in

 

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the ET Fuel System is the Texas Independence pipeline, which was completed in August 2009. With approximately 460 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 ET Fuel System has total system throughput capacity of approximately 5.2 Bcf/d. The major shippers on our pipelines include XTO Energy, Inc., EOG Resources, Inc., Chesapeake Energy Marketing, Inc., Encana Marketing (USA), Inc. and Quicksilver Resources, Inc.

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.

In addition, the ET Fuel System is integrated with our Godley 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

 

Ÿ  

Capacity of 1.2 Bcf/d

Ÿ  

Approximately 600 miles of natural gas pipeline

Ÿ  

Connects Waha to Katy market hubs

The Oasis pipeline is primarily a 36-inch diameter, 600-mile natural gas pipeline that directly connects the Waha Hub to the Katy Hub. 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 and blend untreated natural gas from the Southeast Texas System with gas on the Oasis pipeline while continuing to meet pipeline quality specifications.

Houston Pipeline System (“HPL System”)

 

Ÿ  

Capacity of 5.5 Bcf/d

Ÿ  

Approximately 4,300 miles of natural gas pipeline

Ÿ  

Bammel storage facility with 62 Bcf of total working gas capacity

The HPL System is comprised of approximately 4,300 miles of intrastate natural gas pipeline with an aggregate capacity of 5.5 Bcf/d, the 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 also includes 32 miles of the Cleburne to Carthage pipeline from our Texoma pipeline interconnect to the Carthage Hub. The HPL System is well situated to gather gas in many of the major gas producing areas in Texas including the strong presence in the key Houston Ship Channel and Katy Hub

 

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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, 2009, we had approximately 25.4 Bcf committed under fee-based arrangements with third parties and approximately 27.6 Bcf stored in the facility for our own account.

East Texas Pipeline

 

Ÿ  

Capacity of 2.4 Bcf/d

Ÿ  

Approximately 370 miles of natural gas pipeline

The East Texas pipeline is a 370-mile natural gas pipeline that 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 system. Key shippers on the East Texas pipeline include XTO and EnCana with an average of 420,000 MMBtu/d and 540,000 MMBtu/d, respectively.

Interstate Transportation Pipelines

The following details our pipelines in the interstate transportation segment.

Transwestern Pipeline

 

Ÿ  

Capacity of 2.1 Bcf/d

Ÿ  

Approximately 2,700 miles of interstate natural gas pipeline

The Transwestern pipeline is an open-access natural gas interstate pipeline extending from the gas producing regions of West Texas, eastern and northwest New Mexico, and southern Colorado primarily to pipeline interconnects off the east end of its system and to pipeline interconnects at the California border. Including the Phoenix lateral pipeline completed in February 2009, Transwestern comprises approximately 2,700 miles of pipeline with a capacity of 2.1 Bcf/d. 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 northwest 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 like Arizona, Nevada and California. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users. Transwestern transports natural gas in interstate commerce. As a result, Transwestern qualifies as a “natural gas company” under the Natural Gas Act (“NGA”) and is subject to the regulatory jurisdiction of the FERC.

The Phoenix lateral pipeline consists of 260 miles of pipeline lateral, with a throughput capacity of 500 MMcf/d, connecting the Phoenix area to Transwestern’s existing mainline at Ash Fork, Arizona and approximately 25 miles of 36-inch pipeline looping of Transwestern’s existing San Juan Lateral, adding 375 MMcf/d of capacity.

 

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Midcontinent Express Pipeline

 

Ÿ  

Current capacity of 1.4 Bcf/d on Zone 1 (placed in service in April 2009) and 1.0 Bcf/d on Zone 2 (placed in service in August 2009)

Ÿ  

Planned capacity expansion to 1.8 Bcf/d on Zone 1 and 1.2 Bcf/d on Zone 2

Ÿ  

Approximately 500 miles of interstate natural gas pipeline

Ÿ  

50/50 joint venture with KMP

We constructed, through a 50/50 joint venture arrangement with KMP, the Midcontinent Express pipeline, an approximately 500-mile interstate natural gas pipeline. The Midcontinent Express pipeline originates near Bennington, Oklahoma, is routed through Perryville, Louisiana, and terminates at an interconnect with Transco’s interstate natural gas pipeline in Butler, Alabama, which transports natural gas to the significant natural gas markets in the northeast portion of the United States. The pipeline has a current capacity of 1.4 Bcf/d, all of which capacity has been committed pursuant to firm transportation contracts with shippers for periods ranging from 5 to 10 years. The pipeline has also received long-term transportation contracts related to an additional 0.4 Bcf/d of capacity on Zone 1 and 0.2 Bcf/d of capacity on Zone 2 that is planned to be added through the utilization of additional compression. The first Zone of the pipeline, from Bennington, Oklahoma to Perryville, Louisiana, was placed in service in April 2009, and the second Zone of the pipeline from Perryville, Louisiana to Butler, Alabama, was placed in service in August 2009. The expansion projects are expected to be completed in the latter part of 2010.

Fayetteville Express Pipeline

 

Ÿ  

Initial planned capacity of 2.0 Bcf/d (expected to be in service by the end of 2010)

Ÿ  

Approximately 185 miles of interstate natural gas pipeline

Ÿ  

50/50 joint venture with KMP

See additional description of FEP included in “Recent Developments” above.

Tiger Pipeline

 

Ÿ  

Initial planned capacity of 2.0 Bcf/d (expected to be in service in the first half of 2011)

Ÿ  

Planned expansion of not less than 0.4 Bcf/d (expected to be completed in the second half of 2011)

Ÿ  

Approximately 180 miles of interstate natural gas pipeline

See additional description of Tiger pipeline included in “Recent Developments” above.

Midstream

The following details our assets in the midstream segment.

Southeast Texas System

 

Ÿ  

5,200 miles of natural gas pipeline

Ÿ  

1 natural gas processing plant (the La Grange plant) with aggregate capacity of 240 MMcf/d

Ÿ  

11 natural gas treating facilities with aggregate capacity of 1.3 Bcf/d

Ÿ  

4 natural gas conditioning facilities with aggregate capacity of 670 MMcf/d

The Southeast Texas System is a 5,200-mile integrated system located in southeast Texas 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. The

 

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system includes the La Grange processing plant, 11 treating facilities and 4 conditioning facilities. This system is connected to the Katy Hub through the East Texas pipeline and is also 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 cryogenic natural gas processing plant that processes the rich natural gas that flows through our system to produce residue gas and NGLs. The plant has a processing capacity of approximately 240 MMcf/d.

Our 11 treating facilities have an aggregate capacity of 1.3 Bcf/d. These 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 four conditioning facilities have an aggregate capacity of 670 MMcf/d. These 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.

North Texas System

 

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160 miles of natural gas pipeline

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1 natural gas processing plant (the Godley plant) with aggregate capacity of 500 MMcf/d

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1 natural gas conditioning facility with capacity of 100 MMcf/d

The North Texas System is a 160-mile integrated system located in four counties in North Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett Shale trend. The system includes our Godley plant. The Godley plant processes rich natural gas produced from the Barnett Shale and is connected with the North Texas System and the ET Fuel System. The facility consists of a cryogenic processing plant with processing capacity of approximately 500 MMcf/d and a conditioning facility with approximately 100 MMcf/d of processing capacity.

Canyon Gathering System

 

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1,390 miles of natural gas pipeline

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6 natural gas conditioning facilities with aggregate capacity of 90 MMcf/d

The Canyon Gathering System consists of approximately 1,390 miles of gathering pipeline ranging in diameters from two inches to 16 inches in the Piceance-Uinta Basin of Colorado and Utah and six conditioning plants with an aggregate capacity of 90 MMcf/d.

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 470 MMcf/d, as well as one processing facility.

Marketing Operations

We market the natural gas that flows through our assets, referred to as on-system gas, and also use our marketing operation to 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 supply points and sell the 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.

 

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For the off-system gas, we purchase gas or act as an agent for small independent producers that do 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 impact our expansion and acquisition strategy.

Other Natural Gas Operations

Effective August 17, 2009, we acquired 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 ETP.

In November 2009, we acquired 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.

Business Strategy

The Parent Company Business Strategy

Our current primary business objective is to increase our cash distributions to our Unitholders by actively assisting ETP in executing its business strategy by assisting in identifying, evaluating and pursuing acquisitions and growth opportunities. In general, we expect that we will allow ETP the first opportunity to pursue any acquisition or internal growth project that may be presented to us, which is within the scope of ETP’s operations or business strategy. In the future, we may also support the growth of ETP through the use of our capital resources, which could involve loans, capital contributions or other forms of credit support to ETP. This funding could be used for the acquisition by ETP of a business or asset or for an internal growth project. In addition, the availability of this capital could assist ETP in arranging financing for a project, reducing its financing costs or otherwise supporting a merger or acquisition transaction.

ETP’s Business Strategy

ETP has designed their business strategy with the goal of increasing Unitholder distributions and the value of its Common Units. We believe ETP has engaged, and will continue to engage, in a well-balanced plan for growth through acquisitions, internally generated expansion, and measures aimed at increasing the profitability of our existing assets.

ETP intends to continue to operate as a diversified, growth-oriented master limited partnership with a focus on increasing the amount of cash available for distribution on each ETP Common Unit. We believe that by pursuing independent operating and growth strategies for ETP’s natural gas operations and retail propane business, we will be best positioned to achieve our objectives. ETP balances their desire for growth with their goal of preserving a strong balance sheet, strong liquidity, and investment grade credit metrics.

We expect that acquisitions in natural gas operations will be the primary focus of our acquisition strategy going forward, although we also expect to continue to pursue complementary propane acquisitions. We also anticipate that our natural gas operations will provide internal growth projects of greater scale compared to those available in our propane business as demonstrated by our significant number of completed natural gas pipeline projects as well as our recently announced pipeline projects.

Natural Gas Operations Business Strategies

Enhance profitability of existing assets.  We intend to increase the profitability of our existing asset base by adding new volumes of natural gas under long-term producer commitments, undertaking additional initiatives to enhance utilization and reducing costs by improving operations.

 

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Engage in construction and expansion opportunities.  We intend to leverage our existing infrastructure and customer relationships by constructing and expanding systems to meet new or increased demand for midstream and transportation services.

Increase cash flow from fee-based businesses.  We intend to seek to increase the percentage of our midstream business conducted with third parties under fee-based arrangements in order to reduce our exposure to changes in the prices of natural gas and NGLs.

Growth through acquisitions.  We intend to continue to make strategic acquisitions of midstream, transportation and storage assets in our current areas of operation that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of our existing and acquired assets.

Propane Business Strategies

Pursue internal growth opportunities.  In addition to pursuing expansion through acquisitions, we have aggressively focused on high return internal growth opportunities at our existing customer service locations. We believe that by concentrating our operations in areas experiencing higher-than-average population growth, we are well positioned to achieve internal growth by adding new customers.

Growth through complementary acquisitions.  We believe that our position as one of the three largest propane marketers in the United States provides us a solid foundation to continue our acquisition growth strategy through consolidation.

Maintain low-cost, decentralized operations.  We focus on controlling costs, and we attribute our low overhead costs primarily to our decentralized structure.

Natural Gas Operations Segments

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.

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 2009 by the Energy Information Administration, or the EIA, total domestic consumption of natural gas is expected to remain steady through 2035, with average annual consumption of 23.1 Tcf during that period, compared to 2009 consumption of 22.6 Tcf. The industrial and electricity generation sectors currently account for more than half of natural gas usage in the United States.

Natural gas gathering.  The natural gas gathering process begins with the drilling of wells into gas bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems

 

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generally consist of a network of small diameter pipelines and, if necessary, compression systems that collects natural gas from points near producing wells and transports 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 more 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.

Competition

The business of providing natural gas gathering, transmission, 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.

Credit Risk and Customers

We 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), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposure associated with a single counterparty. Our counterparties

 

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consist primarily of financial institutions, major energy companies and local distribution 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. Based on our policies, exposures, credit and other reserves, management does not anticipate a material adverse effect on financial position or results of operations as a result of counterparty 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 and NGLs have fallen dramatically since July 2008 and have remained at low levels due to the continued effects of the economic recession and higher than normal storage levels. Many of our customers have been negatively impacted by these recent declines in natural gas prices as well as current conditions in the capital markets, which factors have caused several of our customers to announce plans to decrease drilling levels and, in some cases, to consider shutting in natural gas production from some producing wells.

We are diligent in attempting to ensure that we issue credit to credit-worthy customers. However, our purchase and resale of gas exposes us to significant credit risk, as the margin on any sale is generally a very small percentage of the total sales price. Therefore, a credit loss could be significant to our overall profitability.

During the year ended December 31, 2009, none of our customers individually accounted for more than 10% of our midstream, intrastate transportation and storage and interstate segment revenues.

Regulation

Regulation by the FERC of Interstate Natural Gas Pipelines.  The FERC has broad regulatory authority over the business and operations of interstate natural gas pipelines. Under the Natural Gas Act (“NGA”), the FERC generally regulates the transportation of natural gas in interstate commerce. For FERC regulatory purposes, “transportation” includes natural gas pipeline transmission (forwardhauls and backhauls), storage and other services. The Transwestern pipeline transports natural gas in interstate commerce and thus qualifies as a “natural gas company” under the NGA subject to the FERC’s regulatory jurisdiction. We have applied to the FERC for authority to construct, own and operate the Tiger pipeline. We also hold interests in two joint venture projects involving the construction and operation of interstate pipelines: Midcontinent Express pipeline, which was placed into full service in August 2009, and Fayetteville Express pipeline. Subject to possible rehearing and judicial review, the Fayetteville Express pipeline is expected to be in service by the end of 2010. Midcontinent Express pipeline is an NGA-jurisdictional interstate transportation system subject to the FERC’s broad regulatory oversight. Assuming the FERC grants the certificates of public convenience and necessity authorizing the construction, ownership and operation of the Tiger pipeline, the Tiger and the Fayetteville Express pipelines will likewise be NGA-jurisdictional once placed into operation.

The FERC’s NGA authority includes the power to regulate:

 

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the certification and construction of new facilities;

 

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the review and approval of cost-based transportation rates;

 

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the types of services that our regulated assets are permitted to perform;

 

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the terms and conditions associated with these services;

 

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the extension or abandonment of services and facilities;

 

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the maintenance of accounts and records;

 

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the acquisition and disposition of facilities; and

 

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the initiation and discontinuation of services.

 

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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.

In September 2006, Transwestern filed revised tariff sheets under Section 4 of the NGA proposing a general rate increase to be effective on November 1, 2006. In April 2007, the FERC approved a Stipulation and Agreement of Settlement (“Stipulation and Agreement”) that resolved primary components of the rate case. Transwestern’s tariff rates and fuel charges are now final for the period of the settlement. As a part of the Stipulation and Agreement, no settling party shall seek, solicit or financially support a change or challenge to any effective provision of the Stipulation and Agreement during the term of the Stipulation and Agreement. Transwestern is not required to file a new rate case until October 1, 2011.

Rates charged on the Midcontinent Express pipeline are largely governed by long-term negotiated rate agreements, an arrangement approved by the FERC in its July 25, 2008 order granting MEP the certificate of public convenience and necessity to build, own and operate these facilities. In the certificate order, the FERC also approved cost-based recourse rates available to prospective shippers as an alternative to negotiated rates. On December 17, 2009, the FERC issued an order granting FEP authorization to construct and operate the Fayetteville Express pipeline, subject to certain conditions, and FEP accepted the FERC’s certificate. Subject to possible rehearing and judicial review, the pipeline is expected to be in service by late 2010. The rates to be charged for services on the Fayetteville Express pipeline will largely be governed by long-term negotiated rate agreements, an arrangement approved by the FERC in its December 17, 2009 certificate order. In the certificate order, the FERC also approved cost-based recourse rates available to prospective shippers as an alternative to negotiated rates. The application for a certificate of public convenience and necessity to construct the Tiger pipeline was filed with the FERC on August 31, 2009. The FERC has not yet issued an order authorizing the construction of the pipeline and the rate-related arrangements for the services to be provided on these facilities.

The rates to be charged by NGA-jurisdictional natural gas companies 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. Rate increases proposed by the interstate natural gas company may be challenged by protest or by the FERC itself, and if such proposed rate increases are found unjust and unreasonable may be rejected by the FERC in whole or in part. Any successful complaint or protest against the FERC-approved rates of our interstate pipelines could have a prospective impact on our revenues associated with providing interstate transmission services. We 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.

Under the Energy Policy Act of 2005, the FERC possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation activities of non-interstate pipelines and other natural gas market participants. Pursuant to the FERC’s rules promulgated under this statutory directive, 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 Commission 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, or the 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 our physical purchases and sales of natural gas, NGLs or other energy commodities; our gathering or

 

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transportation of these energy commodities; and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by the 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 we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

Failure to comply with the NGA, the Energy Policy Act of 2005 and the other federal laws and regulations governing our operations and business activities can result in the imposition of administrative, civil and criminal remedies.

Intrastate Natural Gas Regulation.  Intrastate transportation of natural gas is largely regulated by the state in which such transportation takes place. To the extent that our intrastate natural gas transportation systems transport natural gas in interstate commerce, the rates, terms and conditions of such services are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act (“NGPA”). The NGPA regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. The rates, terms and conditions of some transportation and storage services provided on the Oasis pipeline, HPL System, East Texas pipeline and ET Fuel System are subject to FERC regulation pursuant to Section 311 of the NGPA. Under Section 311, rates charged for intrastate transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The terms and conditions of service set forth in the intrastate facility’s statement of operating conditions are also subject to the FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than our currently approved Section 311 rates, our 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 the FERC’s ability to assess market forces and detect market manipulation. The FERC also requires certain major non-interstate pipelines to post, on a daily basis, capacity, scheduled flow information and actual flow information. As these posting requirements are currently on appeal before the U.S. 5th Circuit Court of Appeals, it is not known with certainty the precise form these requirements will ultimately take. Full compliance with these regulations could subject us to further costs and administrative burdens, none of which are expected to have a material impact on our operations.

Our intrastate natural gas operations are also subject to regulation by various agencies in Texas, principally the Texas Railroad Commission (“TRRC”). Our 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 not discriminatory. The TRRC has authority to ensure that rates charged by intrastate pipelines for natural gas sales or transportation services are just and reasonable. The rates we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us 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.

Sales of Natural Gas and NGLs.  The price at which we 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 we sell NGLs is not subject to federal or state regulation.

 

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To the extent that we enter into transportation contracts with natural gas pipelines that are subject to FERC regulation, we are subject to FERC requirements related to use of such capacity. Any failure on our 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.

Our 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. The 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. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of the FERC’s regulatory changes may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action in a manner that is materially different from other natural gas marketers with whom we compete.

Gathering Pipeline Regulation.  Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. We own a number of natural gas pipelines in Texas, Louisiana, Colorado and Utah that we believe meet the traditional tests the FERC uses to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. However, the distinction between the FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities 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 in some instances complaint-based rate regulation.

In Texas, our gathering facilities are subject to regulation by the TRRC under the Texas Utilities Code in the same manner as described above for our 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, our Chalkley System is regulated as an intrastate transporter, and the Louisiana Office of Conservation has determined that our Whiskey Bay System is a gathering system.

We are subject to state ratable take and common purchaser statutes in all of the states in which we 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. Our 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. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and

 

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management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Pipeline Safety.  The states in which we conduct operations administer federal pipeline safety standards under the Natural Gas Pipeline Safety Act of 1968, as amended (the “NGPSA”), which requires certain pipelines to comply with safety standards in constructing and operating the pipelines and subjects the pipelines to regular inspections. Failure to comply with the NGPSA may result in the imposition of administrative, civil and criminal remedies. The “rural gathering exemption” under the NGPSA presently exempts substantial portions of our gathering facilities from jurisdiction under that statute. The portions of our 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. The “rural gathering exemption,” however, may be restricted in the future, and it does not apply to our intrastate natural gas pipelines.

Retail Propane Segment

Industry Overview

Propane, a by-product of natural gas processing and petroleum refining, is a clean-burning energy source recognized for its transportability and ease of use relative to alternative forms of stand-alone energy sources. Retail propane use falls into three broad categories: (1) residential applications, (2) industrial, commercial and agricultural applications and (3) other retail applications, including motor fuel sales. In our wholesale operations, we sell propane principally to governmental agencies and industrial end-users.

Propane is extracted from natural gas at processing plants or separated from crude oil during the refining process. Propane is normally transported and stored in a liquid state under moderate pressure or refrigeration for ease of handling in shipping and distribution. When the pressure is released or the temperature is increased, it is usable as a flammable gas. Propane is naturally colorless and odorless. An odorant is added to allow its detection. Like natural gas, propane is a clean burning fuel and is considered an environmentally preferred energy source.

Our propane business is largely seasonal and dependent upon weather conditions in our service areas. Historically, approximately two-thirds of our retail propane volume and substantially all of our propane-related operating income is attributable to sales during the six-month peak-heating season of October through March. This generally results in higher operating revenues and net income in the propane segment during the period from October through March of each year, and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Cash flow from operations is generally greatest when customers pay for propane purchased during the six-month peak-heating season. Sales to commercial and industrial customers are much less weather sensitive.

A substantial portion of our propane is used in the heating-sensitive residential and commercial markets causing the temperatures in our areas of operations, particularly during the six-month peak-heating season, to have a significant effect on the financial performance of our propane operations. In any given area, sustained warmer-than-normal temperatures will tend to result in reduced propane use, while sustained colder-than-normal temperatures will tend to result in greater propane use.

The retail propane segment’s gross profit margins are also affected by customer mix. Sales to residential customers generate higher margins than sales to certain other customer groups, such as commercial or agricultural customers. In addition, propane gross profit margins vary by geographical region. Accordingly, a change in customer or geographic mix can affect propane gross profit without necessarily affecting total revenues.

 

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Competition

Propane competes with other sources of energy, some of which are less costly for equivalent energy value. We compete for customers against suppliers of electricity, natural gas and fuel oil. Competition from alternative energy sources has been increasing as a result of reduced utility regulation. Except for certain industrial and commercial applications, propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because natural gas is a significantly less expensive source of energy than propane. The gradual expansion of natural gas distribution systems in the United States has resulted in the availability of natural gas in many areas that previously depended upon propane. Although the extension of natural gas pipelines tends to displace propane distribution in areas affected, we believe that new opportunities for propane sales arise as more geographically remote neighborhoods are developed. Even though propane is similar to fuel oil in certain applications and market demand, propane and fuel oil compete to a lesser extent primarily because of the cost to the customer to convert from one to another. According to industry publications, propane accounts for 6.5% of household energy consumption in the United States.

In addition to competing with alternative energy sources, we compete with other companies engaged in the distribution business of retail propane. Competition in the propane industry is highly fragmented and generally occurs on a local basis with other large multi-state propane marketers, thousands of smaller local independent marketers and farm cooperatives. Most of our customer service locations compete with five or more marketers or distributors in their area of operations. Each retail distribution outlet operates in its own competitive environment because retail marketers tend to locate in close proximity to customers. The typical retail distribution outlet generally has an effective marketing radius of approximately 50 miles, although in certain rural areas the marketing radius may be extended by satellite locations.

The ability to compete effectively further depends on the reliability of service, responsiveness to customers and the ability to maintain competitive prices. We believe that our safety programs, policies and procedures are more comprehensive than many of our smaller, independent competitors and give us a competitive advantage over such retailers.

Products, Services and Marketing

Our customer service locations are typically located in suburban and rural areas where natural gas is not readily available. Such locations generally consist of a one to two acre parcel of land, an office, a small warehouse and service facility, a dispenser and one or more 18,000 to 30,000 gallon storage tanks. Propane is generally transported from refineries, pipeline terminals, leased storage facilities and coastal terminals by rail or truck transports to our customer service locations where it is unloaded into storage tanks. In order to make a retail delivery of propane to a customer, a bobtail truck, which generally holds 2,500 to 3,000 gallons of propane, is loaded with propane from the storage tank. Propane is then delivered to the customer by the bobtail truck and pumped into a stationary storage tank on the customer’s premises. We also deliver propane to retail customers in portable cylinders. We also deliver propane to certain other bulk end-users of propane in tractor-trailer transports, which typically have an average capacity of approximately 10,500 gallons. End-users receiving transport deliveries include industrial customers, large-scale heating accounts, mining operations and large agricultural accounts.

We encourage our customers whose propane needs are temperature sensitive to implement a regular delivery schedule. Many of our residential customers receive their propane supply pursuant to an automatic delivery system, which eliminates the customer’s need to make an affirmative purchase decision and allows for more efficient route scheduling. We also sell, install and service equipment related to our propane distribution business, including heating and cooking appliances.

Of the retail gallons we sold in 2009, approximately 56% were to residential customers, 29% were to industrial, commercial and agricultural customers and 15% were to other retail users. While sales to residential customers in

 

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2009 accounted for 56% of total retail gallons sold, they accounted for approximately 67% of our gross profit from propane sales. Residential sales have a greater profit margin and a more stable customer base than the other markets we serve. Industrial, commercial and agricultural sales accounted for 21% of our gross profit from propane sales for 2009, with all other retail users accounting for 12%. No single propane customer accounted for 10% or more of consolidated revenues in 2009.

Since home heating usage is the most sensitive to temperature, residential customers account for the greatest usage variation due to weather. Variations in the weather in one or more regions in which we operate can significantly affect the total volumes of propane that we sell and the margins realized thereon and, consequently, our results of operations. We believe that sales to the commercial and industrial markets, while affected by economic patterns, are not as sensitive to variations in weather conditions as sales to residential and agricultural markets.

Propane Supply and Storage

Our supplies of propane historically have been readily available from our supply sources. We purchase from over 40 energy companies and natural gas processors at numerous supply points located in the United States and Canada. In 2009, Enterprise Products Operating L.P. (“Enterprise”) and Targa Liquids Marketing and Trade (“Targa”) provided approximately 50.3% and 14.3% of our combined total propane supply, respectively. Enterprise is a subsidiary of Enterprise GP Holdings, L.P. (“Enterprise GP”), an entity that owns approximately 17.6% of the outstanding ETE Common Units and a 40.6% non-controlling equity interest in LE GP, LLC, the general partner of ETE (“LE GP”). Titan purchases the majority of its propane from Enterprise pursuant to an agreement that expires in 2010 and contains renewal and extension options. Substantially all agreements with Targa have a maximum duration of one year.

In addition, we have a propane purchase agreement with M.P. Oils, Ltd. that expires in 2015, which provided 15.1% of our combined total propane supply during 2009.

We believe that if supplies from Enterprise, Targa or M.P. Oils, Ltd. were interrupted, we would be able to secure adequate propane supplies from other sources without a material disruption of our operations. No other single supplier provided more than 10% of our total domestic propane supply during 2009. Although we cannot guarantee that supplies of propane will be readily available in the future, we believe that our diversification of suppliers will enable us to purchase all of our supply needs at market prices without a material disruption of our operations if supplies are interrupted from any of our existing sources. However, increased demand for propane in periods of severe cold weather, or otherwise, could cause future propane supply interruptions or significant volatility in the price of propane.

Except for ETP’s agreements with Enterprise and M.P. Oils, Ltd., we typically enter into one-year supply agreements. The percentage of contract purchases may vary from year to year. Supply contracts generally provide for pricing in accordance with posted prices at the time of delivery or at the current prices established at major delivery or storage points, and some contracts include a pricing formula that typically is based on these market prices. We generally have attempted to reduce price risk by purchasing propane on a short-term basis. We have on occasion purchased for future resale significant volumes of propane for storage during periods of low demand, which generally occur during the summer months, at the then current market price, both at our customer service locations and in major storage facilities. We receive our supply of propane predominately through railroad tank cars and common carrier transport.

We lease space in larger storage facilities in Michigan, Arizona, New Mexico, Texas, and smaller storage facilities in other locations, and have the opportunity to use storage facilities in additional locations when we “pre-buy” product from sources having such facilities. We believe that we have adequate third party storage to take advantage of supply purchasing advantages as they may occur from time to time. Access to storage facilities

 

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allows us to buy and store large quantities of propane during periods of low demand, which generally occur during the summer months, or at favorable prices, thereby helping to ensure a more secure supply of propane during periods of intense demand or price instability.

Pricing Policy

Pricing policy is an essential element in the marketing of propane. We rely on regional management to set prices based on prevailing market conditions and product cost, as well as local management input. All regional managers are advised regularly of any changes in the posted price of each customer service location’s propane suppliers. In most situations, we believe that our pricing methods will permit us to respond to changes in supply costs in a manner that protects our gross margins and customer base to the extent such protection is possible. In some cases, however, our ability to respond quickly to cost increases could occasionally cause our retail prices to rise more rapidly than those of our competitors, possibly resulting in a loss of customers.

Environmental Matters

The operation of pipelines, plants and other facilities for gathering, compressing, treating, processing or transporting natural gas, NGLs and other products is subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations can impair our business activities that affect the environment in many ways, such as:

 

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restricting how we can release materials or waste products into the air, water, or soils;

 

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limiting or prohibiting construction activities in sensitive areas such as wetlands or areas of endangered species habitat, or otherwise constraining how or when construction is conducted;

 

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requiring remedial action to mitigate pollution from former operations, or requiring plans and activities to prevent pollution from ongoing operations; and

 

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imposing substantial liabilities on us for pollution resulting from our operations, including, for example, potentially enjoining the operations of facilities if it were determined that they did not comply with permit terms.

Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits. We have implemented environmental programs and policies designed to reduce potential liability and costs under applicable environmental laws and regulations.

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Changes in environmental laws and regulations that result in more stringent waste handling, storage, transport, disposal or remediation requirements will increase our cost for performing those activities, and if those increases are sufficiently large, they could have a material adverse effect on our operations and financial position. Moreover, risks of process upsets, accidental releases or spills are associated with our operations, and we cannot guarantee that we will not incur significant costs and liabilities if such upsets, releases or spills were to occur. In the event of future increases in costs, we may be unable to pass on those increases to our customers. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, there is no assurance that this trend will continue in the future.

 

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The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as “CERCLA” or “Superfund,” and comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. One class of “responsible persons” is the current owners or operators of contaminated property, even if the contamination arose as a result of historical operations conducted by previous, unaffiliated occupants of the property. Under CERCLA, “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies, and it also is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. Although “petroleum” is excluded from the definition of hazardous substance under CERCLA, we generate materials in the course of our operations that may be regulated as hazardous substances. We also may incur liability under the Resource Conservation and Recovery Act, also known as “RCRA,” which imposes requirements related to the management and disposal of solid and hazardous wastes. While there exists an exclusion from the definition of hazardous wastes for “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy,” in the course of our operations, we may generate certain types of non-excluded petroleum product wastes as well as ordinary industrial wastes such as paint wastes, waste solvents, and waste compressor oils that may be regulated as hazardous or solid wastes.

We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the measurement, gathering, field compression and processing of natural gas and NGLs. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us, or on or under other locations where such wastes were taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination. A predecessor company acquired by us in July 2001 had previously received and responded to a request for information from the United States Environmental Protection Agency, or “EPA,” regarding its potential contribution to widespread groundwater contamination in San Bernardino, California, known as the Newmark Groundwater Contamination Superfund site. We have not received any follow-up correspondence from EPA on the matter since our acquisition of the predecessor company in 2001. In addition, through our acquisitions of ongoing businesses, we are currently involved in several remediation projects that have cleanup costs and related liabilities. As of December 31, 2009 and 2008, accruals of $12.6 million and $13.3 million, respectively, were recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities to cover estimated material environmental liabilities including certain matters assumed in connection with our acquisition of the HPL System, the Transwestern acquisition, potential environmental liabilities for three sites that were formerly owned by Titan or its predecessors and the predecessor owner’s share of certain environmental liabilities of ETC OLP.

Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the clean up activities include remediation of several compressor sites on the Transwestern system for contamination by polychlorinated biphenyls (“PCBs”) and the costs of this work are not eligible for recovery in rates. The total accrued future estimated cost of remediation activities expected to continue through 2018 is $8.6 million. Transwestern received FERC approval for rate recovery of projected soil and groundwater remediation costs not related to PCBs effective April 1, 2007.

Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing potential PCBs. Future costs cannot be reasonably estimated because remediation activities are undertaken as potential claims are made by customers and former customers. However, such future costs are not expected to have a material impact on our financial position, results of operations or cash flows.

 

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The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state and federal waters. The discharge of pollutants into regulated waters is prohibited, except in accord with the terms of a permit issued by EPA or the state. Any unpermitted release of pollutants, including NGLs or condensates, from our systems or facilities could result in fines or penalties, as well as significant remedial obligations. We believe that we are in substantial compliance with the Clean Water Act. Environmental regulations were recently modified for the EPA’s Spill Prevention, Control and Countermeasures (“SPCC”) program. We are currently reviewing the impact to our operations and expect to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but we believe such costs will not have a material adverse effect on our financial position, results of operations or cash flows.

The Federal Clean Air Act, as amended and comparable state laws restrict the emission of air pollutants from many sources, including processing plants and compressor stations. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, impose stringent air permit requirements or utilize specific equipment or technologies to control emissions. Failure to comply with these laws and regulations could expose us to civil and criminal enforcement actions. We have established agency-approved baseline monitoring of NOx emissions from our Katy Compressor Station in Harris County, Texas, which is in a non-attainment area for ozone. The NOx baseline has been established and we have a sufficient amount of NOx emission allowances that would allow the facility to continue at its current level of operation in the non-attainment area. These plans are subject to possible change however, because the Texas Commission on Environmental Quality (“TCEQ”) is scheduled to develop a plan by April 2010 to respond to the re-designation of the Houston area from a moderate to a severe ozone non-attainment area. By March 2013, TCEQ is required to develop another plan to address the recent change in the ozone standard from 0.08 ppm to 0.075 ppm and the EPA recently proposed to lower the standard even further, to somewhere in between 0.060 and 0.070 ppm. We expect these efforts will result in the adoption of new regulations that may require additional NOx emissions reductions.

In response to scientific studies suggesting that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere, there are a number of parallel initiatives to restrict or regulate emissions of greenhouse gases. On June 26, 2009, the United States House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide “cap and trade” program to reduce domestic emissions of greenhouse gases. ACESA would require a 17 percent reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80 percent reduction of such emissions by 2050. Under this legislation, EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions or suppliers of carbon-based fuels so that such sources could continue to emit greenhouse gases into the atmosphere or market such fuels. The market price of these allowances would be expected to increase significantly over time, thereby encouraging the use of alternative energy sources or greenhouse gas emission control technologies by imposing ever-increasing costs on the use of carbon-based fuels, including NGLs, natural gas, refined petroleum products, and oil. The United States Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and President Obama has indicated his support of legislation to reduce greenhouse gas emissions through an emission allowance system. At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas “cap and trade” programs. These programs operate similarly to the program contemplated by ACESA. Depending on the particular program, we could be required to purchase and surrender emission allowances, either for greenhouse gas emissions resulting from our operations (e.g., compressor stations) or from the combustion of fuels (e.g., natural gas or NGLs) that we process.

 

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Also, as a result of the United States Supreme Court’s decision on April 2, 2007 in Massachusetts, et al.v. EPA, EPA was required to determine whether greenhouse gas emissions posed an endangerment to human health and the environment and whether emissions from mobile sources, such as cars and trucks contributed to that endangerment. On December 7, 2009, the EPA announced its findings that emissions of greenhouse gases present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere causing other climatic changes and that mobile sources are contributing to such endangerment. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In late September 2009, EPA proposed two sets of regulations in anticipation of finalizing its endangerment finding: one to reduce emissions of greenhouse gases from motor vehicles and the other to control emissions of greenhouse gases from stationary sources. Although the motor vehicle rules are expected to be adopted in March 2010, it may take EPA several years to impose regulations limiting emissions of greenhouse gases from stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the annual reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including NGL fractionators and local natural gas distribution companies. Any federal greenhouse gas legislation is expected to prevent EPA from regulating greenhouse gases under existing Clean Air Act regulatory programs to some extent, but if Congress fails to pass greenhouse gas legislation, the EPA is expected to continue its announced greenhouse gas regulatory actions under the Clean Air Act. Any limitation on emissions of greenhouse gases from our equipment and operations or the requirement that we obtain allowances for such emissions, as well as the NGLs that we produce, could require us to incur significant costs to reduce emissions of greenhouse gases associated with our operations or acquire allowances at the prevailing rates in the marketplace.

Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities from powerful winds or rising waters, or increased costs for insurance. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our propane and natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience substantially colder temperatures than their historical averages. As a result, it is difficult to predict how the market for our fuels would be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

Our pipeline operations are subject to regulation by the U.S. Department of Transportation (“DOT”) under the Pipeline Hazardous Materials Safety Administration (“PHMSA”), pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. For the years ended December 31, 2009 and 2008, $31.4 million and $23.3 million, respectively, of capital costs and $18.5 million and $13.1 million, respectively, of operating and maintenance costs have been incurred for pipeline integrity testing. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause ETP to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines.

We are subject to the requirements of the federal Occupational Safety and Health Act, also known as OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s

 

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hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted as the industry standard in all of the states in which we operate. In some states, these laws are administered by state agencies, and in others, they are administered on a municipal level. With respect to the transportation of propane by truck, we are subject to regulations governing the transportation of hazardous materials under the Federal Motor Carrier Safety Act, administered by the DOT. We conduct ongoing training programs to help ensure that our operations are in compliance with applicable regulations. We believe that the procedures currently in effect at all of our facilities for the handling, storage and distribution of propane are consistent with industry standards and are in substantial compliance with applicable laws and regulations.

On December 21, 2009, the Colorado Department of Public Health and Environment Air Pollution Control Division (the “Division”) issued a Compliance Order on Consent (the “Consent Order”) pursuant to which the Division determined that ETC Canyon Pipeline, LLC (“ETC Canyon”) violated certain of its operating and construction permits and Colorado air quality statutes at two natural gas processing plants located in Rio Blanco County, Colorado. In full and final resolution of those matters, ETC Canyon agreed to pay a penalty of $0.2 million. The entry into the Consent Order does not constitute an admission by ETC Canyon of any of the factual or legal determinations of the Division. The Consent Order also requires ETC Canyon to perform testing of the thermal oxidizers at one of its facilities to demonstrate compliance with emissions limits. Following this performance testing, the Division will determine whether it is appropriate to address certain additional issues identified by the Division. We cannot predict what course of action the Division will take; however, we do not expect any future penalties related to this matter to have a material impact on our financial position, results of operations or cash flows.

Employees

As of January 31, 2010, we employed 1,334 persons to operate our natural gas operations. We employed 4,247 full-time employees to operate our propane operations. Of the propane employees, 58 are represented by labor unions. We believe that our relations with our employees are satisfactory. Historically, our propane operations hire seasonal workers to meet peak winter demands.

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.

 

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ITEM 1A.  RISK FACTORS

In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are specific to our structure as a limited partnership, our industry and our company could materially impact our future performance and results of operations. We have provided below a list of these risk factors that should be reviewed when considering an investment in our securities. These are not all the risks we face and other factors currently considered immaterial or unknown to us may impact our future operations.

Risks Inherent in an Investment in Us:

Our only assets are our partnership interests, including the incentive distribution rights, in ETP and, therefore, our cash flow is dependent upon the ability of ETP to make distributions in respect of those partnership interests.

The amount of cash that ETP can distribute to its partners, including us, each quarter depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter and will depend on, among other things:

 

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the amount of natural gas transported in ETP’s pipelines and gathering systems;

 

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the level of throughput in its processing and treating operations;

 

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the fees it charges and the margins it realizes for its gathering, treating, processing, storage and transportation services;

 

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the price of natural gas;

 

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the relationship between natural gas and NGL prices;

 

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the weather in its operating areas;

 

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the cost of the propane it buys for resale and the prices it receives for its propane;

 

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the level of competition from other midstream companies, interstate pipeline companies, propane companies and other energy providers;

 

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the level of its operating costs;

 

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prevailing economic conditions; and

 

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the level of ETP’s derivative activities.

In addition, the actual amount of cash that ETP will have available for distribution will also depend on other factors, such as:

 

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the level of capital expenditures it makes;

 

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the level of costs related to litigation and regulatory compliance matters;

 

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the cost of acquisitions, if any;

 

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the levels of any margin calls that result from changes in commodity prices;

 

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its debt service requirements;

 

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fluctuations in its working capital needs;

 

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its ability to make working capital borrowings under its credit facilities to make distributions;

 

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its ability to access capital markets;

 

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restrictions on distributions contained in its debt agreements; and

 

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the amount, if any, of cash reserves established by its General Partner in its discretion for the proper conduct of ETP’s business.

 

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Because of these factors, we cannot guarantee that ETP 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 has available for distribution depends primarily upon its cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, ETP may make cash distributions during periods when it records net losses and may not make cash distributions during periods when it records net income. Please read “Risks Related to Energy Transfer Partners’ Business” included in this Item 1A for a discussion of further risks affecting ETP’s ability to generate distributable cash flow.

We may not have sufficient cash to pay distributions at our current quarterly distribution level or to increase distributions.

The source of our earnings and cash flow is cash distributions from ETP. Therefore, the amount of distributions we are currently able to make to our Unitholders may fluctuate based on the level of distributions ETP makes to its partners. ETP may not be able to continue to make quarterly distributions at its current level or increase its quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our Unitholders if ETP 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 to us.

Our ability to distribute cash received from ETP to our Unitholders is limited by a number of factors, including:

 

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interest expense and principal payments on our indebtedness;

 

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

 

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our general and administrative expenses;

 

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expenses of our subsidiaries other than ETP, including tax liabilities of our corporate subsidiaries, if any;

 

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capital contributions to maintain our general partner interest in ETP as required by the partnership agreement of ETP upon the issuance of additional partnership securities by ETP; and

 

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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 have little ability to remove our general partner. Our General Partner may not be removed except upon the vote of the holders of at least 66 2/3 % of our outstanding units. Because the equity owners of our General Partner and their affiliates (including Enterprise GP Holdings L.P.) own 109,386,633 Common Units, representing approximately 49% of our outstanding Common Units, it will be particularly difficult for our General Partner to be removed

 

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without the consent of the equity owners of our General Partner and their affiliates. 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 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 Energy Transfer Partners 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 Energy Transfer Partners 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 Energy Transfer Partners 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.

Neither we nor ETP will be prohibited from competing with each other.

Neither our Partnership Agreement nor the Partnership Agreement of ETP prohibits us from owning assets or engaging in businesses that compete directly or indirectly with ETP or prohibit ETP from owning assets or engaging in businesses that compete directly or indirectly with us, except that ETP’s Partnership Agreement prohibits us from engaging in the retail propane business in the United States. In addition, we may acquire, construct or dispose of any assets in the future without any obligation to offer ETP the opportunity to purchase or construct any of those assets, and ETP 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.

Our consolidated debt level and our debt agreements and those of our subsidiaries may limit our ability to make distributions to Unitholders and may limit the distributions we receive from ETP and our future financial and operating flexibility.

As of December 31, 2009, we had approximately $7.79 billion of consolidated debt outstanding, excluding the credit facilities of our joint ventures, which we guarantee in part. Our level of indebtedness affects our operations in several ways, including, among other things:

 

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a significant portion of our and ETP’s cash flow 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;

 

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covenants contained in our and ETP’s existing debt arrangements require us to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business;

 

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our ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership purposes may be limited;

 

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we may be at a competitive disadvantage relative to similar companies that have less debt;

 

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we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level; and

 

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failure to comply with the various restrictive covenants of the debt agreements could negatively impact our ability and the ability of our subsidiaries to incur additional debt, including our ability to utilize the available capacity under our revolving credit facilities, and to pay distributions.

 

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Completion of pipeline expansion projects will require significant amounts of debt and equity financing which may not be available to ETP on acceptable terms, or at all.

ETP plans to fund its expansion capital expenditures, including any future pipeline expansion projects ETP may undertake, with proceeds from sales of ETP’s debt and equity securities and borrowings under ETP’s revolving credit facility; however, ETP cannot be certain that it will be able to issue ETP’s debt and equity securities on terms satisfactory to ETP, or at all. In addition, ETP may be unable to obtain adequate funding under its current revolving credit facility because ETP’s lending counterparties may be unwilling or unable to meet their funding obligations. If ETP is unable to finance its expansion projects as expected, ETP could be required to seek alternative financing, the terms of which may not be attractive to ETP, or to revise or cancel its expansion plans.

As of December 31, 2009, ETP had approximately $6.22 billion of total debt. A significant increase in ETP’s indebtedness that is proportionately greater than ETP’s issuances of equity could negatively impact ETP’s credit ratings or its ability to remain in compliance with the financial covenants under ETP’s revolving credit agreement, which could have a material adverse effect on ETP’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 increases in interest rates. As of December 31, 2009, we had approximately $7.79 billion of total debt. Approximately $6.06 billion of our consolidated debt bears interest at fixed interest rates and $1.73 billion bears interest at variable interest rates. We have entered interest rate swaps for a total notional amount of $1.50 billion, resulting in a net amount of $234.0 million of variable-rate debt at December 31, 2009. We may enter into additional interest rate swap arrangements. As a result, our results of operations, cash flows and financial condition could be materially adversely affected by significant increases in interest rates.

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 owner of our General Partner may be factors in credit evaluations of us as a master 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:

 

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our Unitholders’ current proportionate ownership interest in us will decrease;

 

Ÿ  

the amount of cash available for distribution on each Common Unit or partnership security may decrease;

 

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Ÿ  

the ratio of taxable income to distributions may increase;

 

Ÿ  

the relative voting strength of each previously outstanding Common Unit may be diminished; and

 

Ÿ  

the market price of our Common Units may decline.

In addition, ETP may sell an unlimited number of limited partner interests without the consent of its Unitholders, which will dilute existing interests of its 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 in a merger or in a sale of its equity securities without the consent of our Unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the members of our General Partner to sell or transfer all or part of their ownership interest in our General Partner to a third party. The new owner or owners of our General Partner would then be in a position to replace the directors and officers of our General Partner and control the decisions made and actions taken by the board of directors and officers.

Our General Partner has only one executive officer, and we are dependent on third parties, including key personnel of ETP under a shared services agreement, to provide the financial, accounting, administrative and legal services necessary to operate our business.

John W. McReynolds, the President and Chief Financial Officer of our General Partner, is the only executive officer charged with managing our business other than through our shared services agreement with ETP. We do not currently have a plan for identifying a successor to Mr. McReynolds in the event that he retires, dies or becomes disabled. If Mr. McReynolds ceases to serve as the President and Chief Financial Officer of our General Partner for any reason, we would be without executive management other than through our shared services agreement with ETP until one or more new executive officers are selected by the board of directors of our General Partner. As a consequence, the loss of Mr. McReynolds’ services could have a material negative impact on the management of our business.

Moreover, we rely on the services of key personnel of ETP, including the ongoing involvement and continued leadership of Kelcy L. Warren, one of the founders of ETP’s midstream business, as well as other key members of ETP’s management team such as Marshall S. (Mackie) McCrea, III, President and Chief Operating Officer, and William G. Powers, Jr., President of Propane Operations. 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.

 

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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:

 

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

 

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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 nor ETP may make a distribution to its Unitholders if the distribution would cause Energy Transfer Equity’s or ETP’s respective liabilities to exceed the fair value of their respective assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, partners who received the distribution and knew at the time of the distribution that it violated Delaware law will be liable to the partnership for the distribution amount. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

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

 

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If Energy Transfer Partners GP withdraws or is removed as ETP’s General Partner, then we would lose control over the management and affairs of Energy Transfer Partners, 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 could be cashed out or converted into ETP Common Units at an unattractive valuation.

Under the terms of ETP’s Partnership Agreement, ETP GP will be deemed to have withdrawn as General Partner if, among other things, it:

 

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voluntarily withdraws from the partnership by giving notice to the other partners;

 

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transfers all, but not less than all, of its partnership interests to another entity in accordance with the terms of ETP’s Partnership Agreement;

 

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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

 

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dissolves itself under Delaware law without reinstatement within the requisite period.

In addition, ETP GP can be removed as ETP’s General Partner if that removal is approved by Unitholders holding at least 66 2/3% of ETP’s outstanding common units (including units held by ETP GP and its affiliates). Currently, ETP GP and its affiliates own approximately 33% of ETP’s outstanding common units.

If ETP GP withdraws from being ETP’s General Partner in compliance with ETP’s partnership agreement or is removed from being ETP’s 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 for fair market value. If ETP GP withdraws from being ETP’s General Partner in violation of ETP’s partnership agreement or is removed from being ETP’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 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 held by ETP GP in ETP for fair market value, then the general partner interests and incentive distribution rights held by ETP GP in ETP 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 would lose control over the management and affairs of ETP, 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, to which a significant portion of the value of our Common Units is currently attributable, could be cashed out or converted into ETP Common Units at an unattractive valuation.

Our Partnership Agreement restricts the rights of Unitholders owning 20% or more of our units.

Our Unitholders’ voting rights are restricted by the provision in our partnership agreement generally providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner and its affiliates, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our Unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our Unitholders’ ability to influence the manner or direction of our management. As a result, the price at which our Common Units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

 

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Future sales of the ETP 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, 2009, we owned approximately 62.5 million Common Units of ETP. If we were to sell and/or distribute our ETP 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 outstanding Common Units and our receipt of distributions.

Cost reimbursements due to our General Partner may be substantial and may reduce our ability to pay the distributions to our Unitholders.

Prior to making any distributions to our Unitholders, we will reimburse our General Partner for all expenses it has incurred on our behalf. In addition, our General Partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by our General Partner. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to our Unitholders. Our General Partner has sole discretion to determine the amount of these expenses and fees.

In addition, under Delaware partnership law, our General Partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our General Partner, our General Partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash available for distribution to our Unitholders and cause the value of our Common Units to decline.

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

At December 31, 2009, our consolidated balance sheet reflected $775.0 million of goodwill and $349.7 million of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair market 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’ equity and balance sheet leverage as measured by debt to total capitalization.

Risks Related to Conflicts of Interest

Although we control ETP through our ownership of its General Partner, ETP’s General Partner owes fiduciary duties to ETP and ETP’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, including ETP’s General Partner, on the one hand, and ETP and its Limited Partners, on the other hand. The directors and officers of ETP’s General Partner have fiduciary duties to manage ETP in a manner beneficial to us, its owner. At the same time, the General Partner has a fiduciary duty to manage ETP in a manner beneficial to ETP and its limited partners. The board of directors of ETP’s General Partner will resolve any such conflict and has 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 or that of our Unitholders.

 

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For example, conflicts of interest may arise in the following situations:

 

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the allocation of shared overhead expenses to ETP and us;

 

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the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and ETP, on the other hand;

 

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the determination of the amount of cash to be distributed to ETP’s partners and the amount of cash to be reserved for the future conduct of ETP’s business;

 

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the determination whether to make borrowings under ETP’s revolving working capital facility to pay distributions to ETP’s partners; and

 

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any decision we make in the future to engage in business activities independent of ETP.

The fiduciary duties of our General Partner’s officers and directors may conflict with those of ETP’s General Partner.

Conflicts of interest may arise because of the relationships between ETP’s General Partner, ETP 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, and have fiduciary duties to manage the business of ETP in a manner beneficial to ETP and ETP’s Unitholders. The resolution of these conflicts may not always be in our best interest or that of our Unitholders.

The risk of competition with affiliates of our General Partner has increased.

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. Enterprise GP currently has a 40.6% non-controlling equity interest in our General Partner. Enterprise GP and its subsidiaries own and operate North American midstream energy business that competes with us with respect to our natural gas midstream business.

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 and our Unitholders, which may permit them to favor their own interests to the detriment of us and our Unitholders.

Conflicts of interest may arise among our General Partner and its affiliates, on the one hand, and us and our Unitholders, 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 the interests of our Unitholders. These conflicts include, among others, the following:

 

Ÿ  

Our General Partner is allowed to take into account the interests of parties other than us, including ETP and its 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.

 

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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 to our Unitholders 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.

 

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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 to our Unitholders.

 

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Ÿ  

Our General Partner determines which costs it and its affiliates have incurred are reimbursable by us.

 

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Our Partnership Agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us.

 

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Our General Partner controls the enforcement of obligations owed to us by it and its affiliates.

 

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Our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.

Our partnership agreement limits our General Partner’s fiduciary duties to us and our Unitholders and restricts the remedies available to our Unitholders 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:

 

Ÿ  

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;

 

Ÿ  

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;

 

Ÿ  

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

 

Ÿ  

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.

In order to become a limited partner of our partnership, our Unitholders are required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above.

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, 2009, the equity owners of our General Partner and their affiliates including Enterprise GP Holdings, L.P. own approximately 49% of our Common Units.

 

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We own an interstate pipeline that is 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.

We own an interstate pipeline that is 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.

ETP may issue additional common units, which may increase the risk that ETP will not have sufficient available cash to maintain or increase its per unit distribution level.

The partnership agreement of ETP allows ETP to issue an unlimited number of additional limited partner interests. The issuance of additional common units or other equity securities by ETP will have the following effects:

 

Ÿ  

unitholders’ current proportionate ownership interest in ETP will decrease;

 

Ÿ  

the amount of cash available for distribution on each common unit or partnership security may decrease;

 

Ÿ  

the ratio of taxable income to distributions may increase;

 

Ÿ  

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

 

Ÿ  

the market price of ETP’s common units may decline.

The payment of distributions on any additional units issued by ETP may increase the risk that ETP 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, including obligations under the notes.

Risks Related to Energy Transfer Partners’ Business

Since our cash flows consist exclusively of distributions from ETP, risks to ETP’s business are also risks to us. We have set forth below risks to ETP’s business, the occurrence of which could have a negative impact on ETP’s financial performance and decrease the amount of cash it is able to distribute to us, thereby impacting the amount of cash that we are able to distribute to our Unitholders.

ETP is exposed to the credit risk of its customers, and an increase in the nonpayment and nonperformance by its customers could reduce its ability to make distributions to its Unitholders, including to us.

The risks of nonpayment and nonperformance by ETP’s customers are a major concern in its business. 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 is subject to risks of loss resulting from nonpayment or nonperformance by its customers. The current tightening of credit in the financial markets may

 

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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 customers. Any substantial increase in the nonpayment and nonperformance by ETP’s customers could have a material adverse effect on ETP’s results of operations and operating cash flows.

ETP is exposed to claims by third parties related to the claims that were previously brought against us and ETP by the FERC.

On July 26, 2007, the FERC issued to ETP an Order to Show Cause and Notice of Proposed Penalties (the “Order and Notice”) that contains allegations that ETP violated FERC rules and regulations. The FERC alleged that ETP engaged in manipulative or improper trading activities in the Houston Ship Channel, primarily on two dates during the fall of 2005 following the occurrence of Hurricanes Katrina and Rita, as well as on eight other occasions from December 2003 through August 2005, in order to benefit financially from ETP’s commodities derivatives positions and from certain of ETP’s index-priced physical gas purchases in the Houston Ship Channel. The FERC alleged that during these periods ETP violated the FERC’s then-effective Market Behavior Rule 2, an anti-market manipulation rule promulgated by the FERC under authority of the Natural Gas Act (“NGA”). The FERC alleges that ETP violated this rule by artificially suppressing prices that were included in the Platts Inside FERC Houston Ship Channel index, published by McGraw-Hill Companies, on which the pricing of many physical natural gas contracts and financial derivatives are based. In its Order and Notice, the FERC also alleged that ETP manipulated daily prices at the Waha and Permian Hubs in west Texas on two dates. The FERC also alleged that one of ETP’s intrastate pipelines violated various FERC regulations by, among other things, granting undue preferences in favor of an affiliate. In its Order and Notice, the FERC specified that it was seeking $69.9 million in disgorgement of profits, plus interest, and $82.0 million in civil penalties relating to these market manipulation claims. The FERC specified that it was also seeking to revoke, for a period of 12 months, ETP’s blanket marketing authority for sales of natural gas in interstate commerce at market-based prices.

In February 2008, the FERC’s Enforcement Staff also recommended that the FERC pursue market manipulation claims related to ETP’s trading activities in October 2005 for November 2005 monthly deliveries, a period not previously covered by the FERC’s allegations in the Order and Notice, and that ETP be assessed an additional civil penalty of $25.0 million and be required to disgorge approximately $7.3 million of alleged unjust profits related to this additional month.

On August 26, 2009, ETP entered into a settlement agreement with the FERC’s Enforcement Staff with respect to the pending FERC claims against ETP and on September 21, 2009, the FERC approved the settlement agreement without modification. The agreement settles all outstanding FERC claims against ETP and provides that ETP make a $5.0 million payment to the federal government and establish a $25.0 million fund for the purpose of settling related third-party claims against ETP, including existing litigation claims as well as any new claims that may be asserted against this fund. An administrative law judge appointed by the FERC will determine the validity of any third party claim against this fund. Any party who receives money from this fund will be required to waive all claims against ETP related to this matter. Pursuant to the settlement agreement, the FERC will make no findings of fact or conclusions of law. In addition, the settlement agreement specifies that by exceeding the settlement agreement, ETP does not admit or concede to the FERC or any third party any actual or potential fault, wrongdoing or liability in connection with ETP’s alleged conduct related to the FERC claims. The settlement agreement also requires ETP to maintain specified compliance programs and to conduct independent annual audits of such programs for a two-year period.

We made the $5.0 million payment and established the $25.0 million fund in October 2009. The allocation of the $25.0 million fund is expected to be determined in 2010.

In addition to the FERC legal action, third parties have asserted claims and may assert additional claims against us and ETP alleging damages related to these matters. In this regard, several natural gas producers and a natural

 

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gas marketing company have initiated legal proceedings in Texas state courts against us and ETP for claims related to the FERC claims. These suits contain contract and tort claims relating to alleged manipulation of natural gas prices at the Houston Ship Channel and the Waha Hub in West Texas, as well as the natural gas price indices related to these markets and the Permian Basin natural gas price index during the period from December 2003 through December 2006, and seek unspecified direct, indirect, consequential and exemplary damages. One of the suits against us and ETP contains an additional allegation that we and ETP transported gas in a manner that favored our affiliates and discriminated against the plaintiff, and otherwise artificially affected the market price of gas to other parties in the market. We have moved to compel arbitration and/or contested subject-matter jurisdiction in some of these cases. In one of these cases, the Texas Supreme Court ruled on July 3, 2009 that the state district court erred in ruling that a plaintiff was entitled to pre-arbitration discovery and therefore remanded to the state district court with a direction to rule on our original motion to compel arbitration pursuant to the terms of the arbitration clause in a natural gas contract between us and the plaintiff. This plaintiff has filed a motion with the Texas Supreme Court requesting a rehearing of the ruling.

In February 2008, we were served with a complaint from an owner of royalty interests in natural gas producing properties, individually and on behalf of a putative class of similarly situated royalty owners, working interest owners and producer/operators, seeking arbitration to recover damages based on alleged manipulation of natural gas prices at the Houston Ship Channel. ETP filed an original action in Harris County state court seeking a stay of the arbitration on the ground that the action is not arbitrable, and the state court granted our motion for summary judgment on that issue. This action is currently on appeal before the First Court of Appeals, Houston, Texas.

In October 2007, a consolidated class action complaint was filed against ETP in the United States District Court for the Southern District of Texas. This action alleges that ETP engaged in intentional and unlawful manipulation of the price of natural gas futures and options contracts on the NYMEX in violation of the CEA. It is further alleged that during the class period from December 29, 2003 to December 31, 2005, ETP had the market power to manipulate index prices, and that ETP used this market power to artificially depress the index prices at major natural gas trading hubs, including the Houston Ship Channel, in order to benefit ETP’s natural gas physical and financial trading positions, and that ETP intentionally submitted price and volume trade information to trade publications. This complaint also alleges that ETP violated the CEA by knowingly aiding and abetting violations of the CEA. The plaintiffs state that this allegedly unlawful depression of index prices by ETP manipulated the NYMEX prices for natural gas futures and options contracts to artificial levels during the class period, causing unspecified damages to the plaintiffs and all other members of the putative class who sold natural gas futures or who purchased and/or sold natural gas options contracts on NYMEX during the class period. The plaintiffs have requested certification of their suit as a class action and seek unspecified damages, court costs and other appropriate relief. On January 14, 2008, ETP filed a motion to dismiss this suit on the grounds of failure to allege facts sufficient to state a claim. On March 20, 2008, the plaintiffs filed a second consolidated class action complaint. In response to this new pleading, on May 5, 2008, ETP filed a motion to dismiss the complaint. On March 26, 2009, the court issued an order dismissing the complaint, with prejudice, for failure to state a claim. On April 9, 2009, the plaintiffs moved for reconsideration of the order dismissing the complaint, and on August 26, 2009, the court denied the plaintiffs’ motion for reconsideration. On September 28, 2009, these decisions were appealed by the plaintiffs to the United States Court of Appeals for the 5th Circuit, and the appeal is currently in briefing stage before the court.

In March 2008, a second class action complaint was filed against ETP in the United States District Court for the Southern District of Texas. This action alleges that ETP engaged in unlawful restraint of trade and intentional monopolization and attempted monopolization of the market for fixed-price natural gas baseload transactions at the Houston Ship Channel from December 2003 through December 2005 in violation of federal antitrust law. The complaint further alleges that during this period ETP exerted monopoly power to suppress the price for these transactions to non-competitive levels in order to benefit ETP’s own physical natural gas positions. The plaintiff has, individually and on behalf of all other similarly situated sellers of physical natural gas, requested certification of its suit as a class action and seeks unspecified treble damages, court costs and other appropriate

 

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relief. On May 19, 2008, ETP filed a motion to dismiss this complaint. On March 26, 2009, the court issued an order dismissing the complaint. The court found that the plaintiffs failed to state a claim on all causes of action and for antitrust injury, but granted leave to amend. On April 23, 2009, the plaintiffs filed a motion for leave to amend to assert a claim for common law fraud and attached a proposed amended complaint as an exhibit. ETP opposed the motion and cross-moved to dismiss. On August 7, 2009, the court denied the plaintiff’s motion and granted ETP’s motion to dismiss the complaint. On September 10, 2009, this decision was appealed by the plaintiff to the United States Court of Appeals for the 5th Circuit, and the appeal is currently in briefing stage before the court.

ETP is expensing the legal fees, consultants’ fees and other expenses relating to these matters in the periods in which such costs are incurred. We do not have any accruals for litigation and other contingencies as of December 31, 2009. Although the $25.0 million fund required by the settlement agreement with the FERC is to be applied to resolve third party claims, including the existing third party litigation described above, it is possible that the amount ETP becomes obliged to pay to resolve third party litigation related to these matters, whether on a negotiated settlement basis or otherwise, will exceed the amount of the fund. In accordance with applicable accounting standards, ETP will review the amount of their accrual related to these matters as developments related to these matters occur and ETP will adjust their accrual if ETP determines that it is probable that the amount ETP may ultimately become obliged to pay as a result of the final resolution of these matters is greater than the amount of ETP’s accrual for these matters. As ETP’s accrual amounts are non-cash, any cash payment of an amount in resolution of these matters would likely be made from cash from operations or borrowings, which payments would reduce ETP’s cash available to service ETP’s indebtedness either directly or as a result of increased principal and interest payments necessary to service any borrowings incurred to finance such payments. If these payments are substantial, ETP may experience a material adverse impact on its results of operations and its liquidity.

The profitability of certain activities in ETP’s midstream and intrastate transportation and storage operations are largely dependent upon natural gas commodity prices, price spreads between two or more physical locations and market demand for natural gas and NGLs, which are factors beyond ETP’s control and have been volatile.

Income from ETP’s midstream and intrastate transportation and storage operations is exposed to risks due to fluctuations in commodity prices. For a portion of the natural gas gathered at the North Texas System, Southeast Texas System and at ETP’s HPL System, ETP purchases natural gas from producers at the wellhead and then gathers and delivers the natural gas to pipelines where ETP typically resells the natural gas under various arrangements, including sales at index prices. Generally, the gross margins ETP realizes under these arrangements decrease in periods of low natural gas prices.

For a portion of the natural gas gathered and processed at the North Texas System and Southeast Texas System, ETP enters into percentage-of-proceeds arrangements, keep-whole arrangements, and processing fee agreements pursuant to which ETP agrees to gather and process natural gas received from the producers. Under percentage-of-proceeds arrangements, ETP generally sells the residue gas and NGLs at market prices and remits 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, ETP delivers an agreed upon percentage of the residue gas and NGL volumes to the producer and sells the volumes it keeps to third parties at market prices. Under these arrangements, ETP’s 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 ETP’s results of operations. Under keep-whole arrangements, ETP generally sells the NGLs produced from its 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 the natural gas, ETP 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, ETP’s revenues and gross margins decrease when the price of natural gas increases relative to the price of NGLs if ETP is not able to bypass its processing plants and sell the unprocessed natural gas. Under

 

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

In the past, the prices of natural gas and NGLs have been extremely volatile, and ETP expects this volatility to continue. For example, during ETP’s year ended December 31, 2009, the NYMEX settlement price for the prompt month contract ranged from a high of $6.14 per MMBtu to a low of $2.84 per MMBtu. A composite of the Mt. Belvieu average NGLs price based upon ETP’s average NGLs composition during ETP’s year ended December 31, 2009 ranged from a high of approximately $1.17 per gallon to a low of approximately $0.57 per gallon.

ETP’s Oasis pipeline, East Texas pipeline, ET Fuel System and HPL System receive fees for transporting natural gas for its customers. Although a significant amount of the pipeline capacity of the East Texas pipeline and various pipeline segments of the ET Fuel System is committed under long-term fee-based contracts, the remaining capacity of ETP’s transportation pipelines is subject to fluctuation in demand based on the markets and prices for natural gas, which factors may result in decisions by natural gas producers to reduce production of natural gas during periods of lower prices for natural gas or may result in decisions by end-users of natural gas to reduce consumption of these fuels during periods of higher prices for these fuels. ETP’s fuel retention fees are also directly impacted by changes in natural gas prices. Increases in natural gas prices tend to increase ETP’s fuel retention fees, and decreases in natural gas prices tend to decrease its fuel retention fees.

The markets and prices for natural gas and NGLs depend upon factors beyond ETP’s control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions, and other factors, including:

 

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the impact of weather on the demand for oil and natural gas;

 

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the level of domestic oil and natural gas production;

 

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the availability of imported oil and natural gas;

 

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actions taken by foreign oil and gas producing nations;

 

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the availability of local, intrastate and interstate transportation systems;

 

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the price, availability and marketing of competitive fuels;

 

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the demand for electricity;

 

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the impact of energy conservation efforts; and

 

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the extent of governmental regulation and taxation.

The use of derivative financial instruments could result in material financial losses by ETP.

From time to time, ETP has sought to limit a portion of the adverse effects resulting from changes in natural gas and other commodity prices and interest rates by using derivative financial instruments and other risk management mechanisms and by ETP’s marketing and/or system optimization activities. To the extent that ETP 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 in ETP’s favor. In addition, even though monitored by management, ETP’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 physical or financial positions or hedging policies and procedures are not followed.

 

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ETP’s success depends upon its ability to continually contract for new sources of natural gas supply.

In order to maintain or increase throughput levels on ETP’s gathering and transportation pipeline systems and asset utilization rates at its treating and processing plants, ETP must continually contract for new natural gas supplies and natural gas transportation services. ETP may not be able to obtain additional contracts for natural gas supplies for its natural gas gathering systems, and it may be unable to maintain or increase the levels of natural gas throughput on its transportation pipelines. The primary factors affecting ETP’s ability to connect new supplies of natural gas to its gathering systems include its success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity and production of natural gas near ETP’s gathering systems or in areas that provide access to its transportation pipelines or markets to which its systems connect. The primary factors affecting ETP’s ability to attract customers to its transportation pipelines consist of its access to other natural gas pipelines, natural gas markets, natural gas-fired power plants and other industrial end-users and the level of drilling and production of natural gas in areas connected to these pipelines and systems.

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity and production generally decrease as oil and natural gas prices decrease. ETP has no control over the level of drilling activity in its areas of operation, the amount of reserves underlying the wells and the rate at which production from a well will decline, sometimes referred to as the “decline rate.” In addition, ETP has no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital.

A substantial portion of ETP’s assets, including its gathering systems and its processing and treating plants, are connected to natural gas reserves and wells for which the production will naturally decline over time. Accordingly, ETP’s cash flows will also decline unless it is able to access new supplies of natural gas by connecting additional production to these systems.

ETP’s transportation pipelines are also dependent upon natural gas production in areas served by its pipelines or in areas served by other gathering systems or transportation pipelines that connect with its transportation pipelines. A material decrease in natural gas production in ETP’s areas of operation or in other areas that are connected to ETP’s areas of operation by third party gathering systems or pipelines, as a result of depressed commodity prices or otherwise, would result in a decline in the volume of natural gas ETP handles, which would reduce ETP’s revenues and operating income. In addition, ETP’s future growth will depend, in part, upon whether it can contract for additional supplies at a greater rate than the natural decline rate in ETP’s currently connected supplies.

Transwestern derives a significant portion of its revenue from charging its customers for reservation of capacity, which revenues Transwestern receives regardless of whether these customers actually use the reserved capacity. Transwestern also generates revenue from transportation of natural gas for customers without reserved capacity. If the reserves available through the supply basins connected to Transwestern’s systems decline, a decrease in development or production activity could cause a decrease in the volume of natural gas available for transmission or a decrease in demand for natural gas transportation on the Transwestern system over the long run.

The volumes of natural gas ETP transports on its intrastate transportation pipelines may be reduced in the event that the prices at which natural gas is purchased and sold at the Waha Hub, the Katy Hub, the Carthage Hub and the Houston Ship Channel Hub, the four major natural gas trading hubs served by ETP’s pipelines, become unfavorable in relation to prices for natural gas at other natural gas trading hubs or in other markets as customers may elect to transport their natural gas to these other hubs or markets using pipelines other than those ETP operates.

 

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ETP may not be able to fully execute its growth strategy if it encounters increased competition for qualified assets.

ETP’s strategy contemplates growth through the development and acquisition of a wide range of midstream, transportation, storage, propane and other energy infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance its ability to compete effectively and diversify its asset portfolio, thereby providing more stable cash flow. ETP regularly considers and enters into discussions regarding, and are currently contemplating, the acquisition of additional assets and businesses, stand alone development projects or other transactions that ETP believes will present opportunities to realize synergies and increase its cash flow.

Consistent with ETP’s acquisition strategy, management is continuously engaged in discussions with potential sellers regarding the possible acquisition of additional assets or businesses. Such acquisition efforts may involve ETP 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 believes it is the only party or one of a very limited number of potential buyers in negotiations with the potential seller. We cannot guarantee that ETP’s current or future acquisition efforts will be successful or that any such acquisition will be completed on terms considered favorable to ETP.

In addition, ETP is experiencing increased competition for the assets it purchases or contemplates purchasing. Increased competition for a limited pool of assets could result in ETP losing to other bidders more often or acquiring assets at higher prices, both of which would limit ETP’s ability to fully execute its growth strategy. Inability to execute its growth strategy may materially adversely impact ETP’s results of operations.

If ETP does not make acquisitions on economically acceptable terms, its future growth could be limited.

ETP’s results of operations and its ability to grow and to increase distributions to Unitholders will depend in part on its ability to make acquisitions that are accretive to ETP’s distributable cash flow per unit.

ETP may be unable to make accretive acquisitions for any of the following reasons, among others:

 

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because ETP is unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

 

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because ETP is unable to raise financing for such acquisitions on economically acceptable terms; or

 

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because ETP is outbid by competitors, some of which are substantially larger than ETP and have greater financial resources and lower costs of capital then it does.

Furthermore, even if ETP 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 may:

 

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fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;

 

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decrease its liquidity by using a significant portion of its available cash or borrowing capacity to finance acquisitions;

 

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significantly increase its interest expense or financial leverage if ETP incurs additional debt to finance acquisitions;

 

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encounter difficulties operating in new geographic areas or new lines of business;

 

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incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which ETP is not indemnified or for which the indemnity is inadequate;

 

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Ÿ  

be unable to hire, train or retrain qualified personnel to manage and operate its growing business and assets;

 

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less effectively manage its historical assets, due to the diversion of ETP management’s attention from other business concerns; or

 

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incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.

If ETP consummates future acquisitions, its capitalization and results of operations may change significantly. As ETP determines the application of its funds and other resources, Unitholders will not have an opportunity to evaluate the economics, financial and other relevant information that ETP will consider.

If ETP does not continue to construct new pipelines, its future growth could be limited.

During the past several years, ETP has constructed several new pipelines, and ETP is currently involved in constructing several new pipelines. ETP’s results of operations and its ability to grow and to increase distributable cash flow per unit will depend, in part, on its ability to construct pipelines that are accretive to ETP’s distributable cash flow. ETP may be unable to construct pipelines that are accretive to distributable cash flow for any of the following reasons, among others:

 

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ETP is unable to identify pipeline construction opportunities with favorable projected financial returns;

 

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ETP is unable to raise financing for its identified pipeline construction opportunities; or

 

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ETP is unable to secure sufficient natural gas transportation commitments from potential customers due to competition from other pipeline construction projects or for other reasons.

Furthermore, even if ETP constructs a pipeline that it believes will be accretive, the pipeline may in fact adversely affect its results of operations or results from those projected prior to commencement of construction and other factors.

Expanding ETP’s business by constructing new pipelines and treating and processing facilities subjects it to risks.

One of the ways that ETP has grown its business is through the construction of additions to its existing gathering, compression, treating, processing and transportation systems. The construction of a new pipeline or the expansion of an existing pipeline, by adding additional compression capabilities or by adding a second pipeline along an existing pipeline, and the construction of new processing or treating facilities, involve numerous regulatory, environmental, political and legal uncertainties beyond ETP’s control and require the expenditure of significant amounts of capital that ETP will be required to finance through borrowings, the issuance of additional equity or from operating cash flow. If ETP undertakes these projects, they may not be completed on schedule, at all or at the budgeted cost. ETP currently has several major expansion and new build projects planned or underway, including the Fayetteville Express pipeline and the Tiger pipeline. A variety of factors outside ETP’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 has resulted in, and may continue to 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 results of operations and cash flows. Moreover, ETP’s revenues may not increase immediately following the completion of a particular project. For instance, if ETP builds a new pipeline, the construction will occur over an extended period of time, but ETP may not materially increase its revenues until long after the project’s completion. In addition, the success of a pipeline construction project will likely depend upon the level of natural gas exploration and development drilling activity and the demand for pipeline transportation in the areas proposed to be serviced by the project as well as ETP’s ability to obtain commitments from producers in this area to utilize the newly constructed pipelines. In this regard, ETP may construct facilities to capture anticipated future growth in natural gas production in a region in which such growth does not

 

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materialize. As a result, new facilities may be unable to attract enough throughput or contracted capacity reservation commitments to achieve ETP’s expected investment return, which could adversely affect its results of operations and financial condition.

ETP depends on certain key producers for its supply of natural gas on the Southeast Texas System and North Texas System and the loss of any of these key producers could adversely affect its financial results.

For ETP’s year ended December 31, 2009, EnCana Oil and Gas (USA), Inc., XTO Energy Inc. (“XTO”), SandRidge Energy Inc. and EnerVest Operating, LLC, supplied ETP with approximately 70% of the Southeast Texas System’s natural gas supply. In December 2009, Exxon Mobil Corporation (“ExxonMobil”) and XTO announced an agreement whereby ExxonMobil will acquire XTO. For ETP’s year ended December 31, 2009, Chesapeake Energy Marketing, Inc., XTO, EOG Resources, Inc., and EnCana Oil and Gas (USA), Inc., supplied ETP with approximately 84% of the North Texas System’s natural gas supply. ETP is not the only option available to these producers for disposition of the natural gas they produce. To the extent that these and other producers may reduce the volumes of natural gas that they supply ETP, ETP would be adversely affected unless it was able to acquire comparable supplies of natural gas from other producers.

ETP depends on key customers to transport natural gas through its pipelines.

ETP has nine- and ten-year fee-based transportation contracts with XTO that terminate in 2013 and 2017, respectively, pursuant to which XTO has committed to transport certain minimum volumes of natural gas on pipelines in our ET Fuel System. ExxonMobil’s pending acquisition of XTO, expected to be completed in the second quarter of 2010, is not expected to result in any changes to these commitments. ETP also has an eight-year fee-based transportation contract with TXU Portfolio Management Company, L.P., a subsidiary of TXU Corp. (“TXU Shipper”) to transport natural gas on the ET Fuel System to TXU’s electric generating power plants. ETP has also entered into two eight-year natural gas storage contracts that terminate in 2012 with TXU Shipper to store natural gas at the two natural gas storage facilities that are part of the ET Fuel System. Each of the contracts with TXU Shipper may be extended by TXU Shipper for two additional five-year terms. The failure of XTO Energy or TXU Shipper to fulfill their contractual obligations under these contracts could have a material adverse effect on ETP’s cash flow and results of operations if ETP was not able to replace these customers under arrangements that provide similar economic benefits as these existing contracts.

The major shippers on ETP’s intrastate transportation pipelines include XTO, EOG Resources, Inc., Chesapeake Energy Marketing, Inc., EnCana Marketing (USA), Inc. and Quicksilver Resources, Inc. These shippers have long-term contracts that have remaining terms ranging from 2 to 11 years.

Transwestern generates the majority of its revenues from long-term and short-term firm transportation contracts with natural gas producers, local distribution companies and end-users. During 2009, ConocoPhillips, Salt River Project and BP Energy Company collectively accounted for 32% of Transwestern’s total revenues.

The failure of the major shippers on our intrastate and interstate transportation pipelines to fulfill their contractual obligations could have a material adverse effect on ETP’s and our cash flow and results of operations if ETP was not able to replace these customers under arrangements that provide similar economic benefits as these existing contracts.

With respect to ETP’s interstate transportation operations, MEP, the joint venture entity formed to construct and operate the Midcontinent Express pipeline, has secured predominantly 10-year firm transportation contracts from a small number of major shippers for all of the current 1.4 Bcf/d of capacity on the Midcontinent Express pipeline. MEP has also secured firm transportation commitments related to additional capacity on the Midcontinent Express pipeline, which expansion was approved by the FERC in September 2009. The planned capacity expansions to 1.8 Bcf/d are expected to be completed in the latter part of 2010. FEP has secured binding 10-year commitments from a small number of major shippers for approximately 1.85 Bcf/d of firm transportation

 

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service on the 2.0 Bcf/d Fayetteville Express pipeline project. In connection with our Tiger pipeline project, ETP has entered into an agreement with Chesapeake Energy Marketing, Inc. that provides for a 15-year commitment for firm transportation capacity of approximately 1.0 Bcf/d. ETP has also entered into agreements with EnCana Marketing (USA), Inc. and other shippers that provide for 10-year commitments for firm transportation capacity on the Tiger pipeline, bringing the initial design capacity to 2.0 Bcf/d in the aggregate. In February 2010, we announced that we had entered into a 10-year commitment for an additional 400 MMcf/d. The failure of these key shippers to fulfill their contractual obligations could have a material adverse effect on ETP’s cash flow and results of operations if ETP was not able to replace these customers under arrangements that provide similar economic benefits as these existing contracts.

Federal, state or local regulatory measures could adversely affect the business and operations of ETP’s midstream and intrastate assets.

ETP’s midstream and intrastate transportation and storage operations are generally exempt from FERC regulation under the NGA, but FERC regulation still significantly affects its business and the market for its products. The rates, terms and conditions of some of the transportation and storage services ETP provides on the HPL System, the East Texas pipeline, the Oasis pipeline and the ET Fuel System are subject to FERC regulation under Section 311 of the NGPA. Under Section 311, rates charged for transportation and storage must be fair and equitable amounts. Amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s statement of operating conditions, are subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than its currently approved rates, ETP may suffer a loss of revenue. Failure to observe the service limitations applicable to storage and transportation service under Section 311, and 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 penalties.

FERC has adopted new market-monitoring and annual and quarterly reporting regulations, which regulations are applicable to many intrastate pipelines as well as other entities that are otherwise not subject to FERC’s NGA jurisdiction, such as natural gas marketers. These regulations are intended to increase the transparency of wholesale energy markets, to protect the integrity of such markets, and to improve FERC’s ability to assess market forces and detect market manipulation. These regulations may result in administrative burdens and additional compliance costs for ETP.

ETP holds transportation contracts with interstate pipelines that are subject to FERC regulation. As a shipper on an interstate pipeline, ETP is subject to FERC requirements related to use of the interstate capacity. Any failure on ETP’s part to comply with the FERC’s regulations or orders could result in the imposition of administrative, civil and criminal penalties.

ETP’s intrastate transportation and storage operations are subject to state regulation in Texas, New Mexico, Arizona, Louisiana, Utah and Colorado, the states in which ETP operates these types of natural gas facilities. ETP’s intrastate transportation operations located in Texas are subject to regulation as common purchasers and as gas utilities by the TRRC. The TRRC’s jurisdiction extends to both rates and pipeline safety. The rates ETP charges for transportation and storage services are deemed just and reasonable under Texas law unless challenged in a complaint. Should a complaint be filed or should regulation become more active, ETP’s business may be adversely affected.

ETP’s midstream and intrastate transportation operations are also subject to ratable take and common purchaser statutes in Texas, New Mexico, Arizona, Louisiana, Utah and Colorado. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting ETP’s right as an

 

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owner of gathering facilities to decide with whom ETP contracts to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and some of the states in which ETP operates have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which ETP operates that have adopted some form of complaint-based regulation, like Texas, generally allow natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering rates and access. Other state and local regulations also affect ETP’s business.

ETP’s storage facilities are also subject to the jurisdiction of the TRRC. Generally, the TRRC has jurisdiction over all underground storage of natural gas in Texas, unless the facility is part of an interstate gas pipeline facility. Because the natural gas storage facilities of the ET Fuel System and HPL System are only connected to intrastate gas pipelines, they fall within the TRRC’s jurisdiction and must be operated pursuant to TRRC permit. Certain changes in ownership or operation of TRRC-jurisdictional storage facilities, such as facility expansions and increases in the maximum operating pressure, must be approved by the TRRC through an amendment to the facility’s existing permit. In addition, the TRRC must approve transfers of the permits. Texas laws and regulations also require all natural gas storage facilities to be operated to prevent waste, the uncontrolled escape of gas, pollution and danger to life or property. Accordingly, the TRRC requires natural gas storage facilities to implement certain safety, monitoring, reporting and record-keeping measures.

Violations of the terms and provisions of a TRRC permit or a TRRC order or regulation can result in the modification, cancellation or suspension of an operating permit and/or civil penalties, injunctive relief, or both.

The states in which ETP conducts operations administer federal pipeline safety standards under the Pipeline Safety Act of 1968, which requires certain pipeline companies to comply with safety standards in constructing and operating the pipelines, and subjects pipelines to regular inspections. Some of ETP’s gathering facilities are exempt from the requirements of this Act. In respect to recent pipeline accidents in other parts of the country, Congress and the Department of Transportation have passed or are considering heightened pipeline safety requirements.

Failure to comply with applicable laws and regulations could result in the imposition of administrative, civil and criminal remedies.

ETP’s interstate pipelines are subject to laws, regulations and policies governing the rates they are allowed to charge for their services.

Laws, regulations and policies governing interstate natural gas pipeline rates could affect the ability of ETP’s interstate pipelines to establish rates, to charge rates that would cover future increases in its costs, or to continue to collect rates that cover current costs. NGA-jurisdictional natural gas companies must charge rates that are deemed just and reasonable by the FERC. The rates charged by natural gas companies are generally required to be on file with the FERC in FERC-approved tariffs. Pursuant to the NGA, existing tariff rates may be challenged by complaint and rate increases proposed by the natural gas company may be challenged by protest. ETP also may be limited by the terms of negotiated rate agreements from seeking future rate increases, or constrained by competitive factors from charging its FERC-approved maximum just and reasonable tariff rates. Further, rates must, for the most part, be cost-based and the FERC has the ability, on a prospective basis, to order refunds of amounts collected under rates that have been found by the FERC to be in excess of a just and reasonable level.

Transwestern made a general rate case filing under Section 4 of the NGA in September 2006. The rates in this proceeding were settled and are final and no longer subject to refund. Transwestern is not required to file a new general rate case until October 2011. However, shippers (other than shippers that have agreed, as parties to the Stipulation and Agreement, not to challenge Transwestern’s tariff rates through the remaining term of the settlement) have the statutory ability to challenge the lawfulness of tariff rates that have become final and effective. The FERC may also investigate such rates absent shipper complaint.

 

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Most of the rates to be paid by the initial shippers on the Midcontinent Express pipeline are established pursuant to long-term, negotiated rate transportation agreements. Other prospective shippers on Midcontinent Express pipeline that elect not to pay a negotiated rate for service may opt instead to pay a cost-based recourse rate established by the FERC as part of Midcontinent Express pipeline’s certificate of public convenience and necessity. Negotiated rate agreements generally provide a degree of certainty to the pipeline and shipper as to a fixed rate during the term of the relevant transportation agreement, but such agreements can limit the pipeline’s future ability to collect costs associated with construction and operation of the pipeline that might be higher than anticipated at the time the negotiated rate agreement was entered. FERC applications for authorization to construct, own and operate the Fayetteville Express pipeline and the Tiger pipeline were filed on June 15, 2009 and August 31, 2009, respectively. On December 17, 2009, the FERC issued an order granting authorization to construct, own and operated the Fayetteville Express pipeline, subject to certain conditions. While FEP has accepted the FERC’s certificate authorization, this order is subject to a limited request for rehearing and possible judicial review. FERC has not yet determined whether the Tiger pipeline should be granted the requested authority. ETP cannot predict if, or when and with what conditions, FERC authorization for the Tiger pipeline will be granted.

Any successful challenge to the rates of ETP’s interstate natural gas companies, whether brought by complaint, protest or investigation, could reduce its revenues associated with providing transportation services on a prospective basis. We and ETP cannot guarantee that ETP’s interstate pipelines will be able to recover all of their costs through existing or future rates.

The ability of interstate pipelines held in tax-pass-through entities, like ETP, to include an allowance for income taxes in their regulated rates has been subject to extensive litigation before the FERC and the courts, and the FERC’s current policy is subject to future refinement or change.

The ability of interstate pipelines held in tax-pass-through entities, like ETP, to include an allowance for income taxes as a cost-of-service element in their regulated rates has been subject to extensive litigation before the FERC and the courts for a number of years. It is currently the 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 the FERC on a case-by-case basis. Under the FERC’s policy, ETP thus remains eligible to include an income tax allowance in the tariff rates its charges for interstate natural gas transportation. The application of that policy remains subject to future refinement or change by the FERC. With regard to rates charged and collected by Transwestern, the allowance for income taxes as a cost-of-service element in ETP’s tariff rates is generally not subject to challenge prior to the expiration of its settlement agreement in 2011.

The interstate pipelines are subject to laws, regulations and policies governing terms and conditions of service, which could adversely affect their business and operations.

In addition to rate oversight, the FERC’s regulatory authority extends to many other aspects of the business and operations of ETP’s interstate pipelines, including:

 

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terms and conditions of service;

 

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the types of services interstate pipelines may offer their customers;

 

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construction of new facilities;

 

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acquisition, extension or abandonment of services or facilities;

 

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reporting and information posting requirements;

 

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accounts and records; and

 

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relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.

 

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Compliance with these requirements can be costly and burdensome. Future changes to laws, regulations and policies in these areas may impair the ability of ETP’s interstate pipelines to compete for business, may impair their ability to recover costs or may increase the cost and burden of operation.

We must on occasion rely upon rulings by FERC or other governmental authorities to carry out certain of our business plans. For example, in order to carry out our plan to construct the Fayetteville Express and Tiger pipelines we had have 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. Although the FERC has authorized the construction and operation of the Fayetteville Express pipeline, subject to certain conditions, this order is still subject to limited rehearing and possible judicial review. The FERC has not yet ruled upon the Tiger pipeline application and we and ETP cannot guarantee that the FERC will authorize construction and operation of that pipeline or any future interstate natural gas transportation project we might propose. Moreover, there is no guarantee that, if granted, certificate authority for the Tiger pipeline, or any future interstate projects, will be granted in a timely manner or will be free from potentially burdensome conditions.

Similarly, ETP 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 us 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. We cannot guarantee 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 MEP project. We cannot guarantee that these post-certification orders will not be altered on rehearing or that these orders will not be subject to judicial review.

Failure to comply with all applicable FERC-administered statutes, rules, regulations and orders, could bring substantial penalties and fines. Under the Energy Policy Act of 2005, the FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation. The FERC possesses similar authority under the NGPA.

Finally, we and ETP cannot give any assurance regarding the likely future regulations under which ETP will operate its interstate pipelines or the effect such regulation could have on its business, financial condition, and results of operations.

ETP’s business involves hazardous substances and may be adversely affected by environmental regulation.

ETP’s natural gas as well as its propane operations are subject to stringent federal, state, and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of permits for our operations, result in capital expenditures to manage, limit, or prevent emissions, discharges or releases of various materials from ETP’s pipelines, plants and facilities and impose substantial liabilities for pollution resulting from ETP’s operations. Several governmental authorities, such as the U.S. Environmental Protection Agency, 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 administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctive relief.

ETP may incur substantial environmental costs and liabilities because of the underlying risk inherent to its operations. Environmental laws provide for joint and several strict liability for cleanup costs incurred to address discharges or releases of petroleum hydrocarbons or wastes on, under or from ETP’s properties and facilities, many of which have been used for industrial activities for a number of years, even if such discharges were caused by its predecessors. Private parties, including the owners of properties through which ETP’s gathering systems pass or facilities where its petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have

 

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the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations, personal injury or property damage. The total accrued future estimated cost of remediation activities relating to ETP’s Transwestern pipeline operations expected to continue through 2018 is $8.6 million.

Changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, emission standards, or storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. For example, the EPA in 2008 lowered the federal ozone standard from 0.08 parts per million to 0.075 parts per million, requiring the environmental agencies in states with areas that do not currently meet this standard to adopt new rules between to further reduce NOx and other ozone precursor emissions. The EPA recently proposed to lower the standard even further, to somewhere between 0.060 and 0.070 ppm. We have previously been able to satisfy the more stringent NOx emission reduction requirements that affect our compressor units in ozone non-attainment areas at reasonable cost, but there is no guarantee that the changes we may have to make in the future to meet the new ozone standard or other evolving standards will not require us to incur costs that could be material to our operations.

In response to scientific studies suggesting that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere, there are a number of parallel initiatives to restrict or regulate emissions of greenhouse gases. On June 26, 2009, the United States House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide “cap and trade” program to reduce domestic emissions of greenhouse gases. ACESA would require a 17 percent reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80 percent reduction of such emissions by 2050. Under this legislation, EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions or suppliers of carbon-based fuels so that such sources could continue to emit greenhouse gases into the atmosphere or market such fuels. The market price of these allowances would be expected to increase significantly over time, thereby encouraging the use of alternative energy sources or greenhouse gas emission control technologies by imposing ever-increasing costs on the use of carbon-based fuels, including NGLs, natural gas, refined petroleum products, and oil. The United States Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and President Obama has indicated his support of legislation to reduce greenhouse gas emissions through an emission allowance system. At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas “cap and trade” programs. These programs operate similarly to the program contemplated by ACESA. Depending on the particular program, we could be required to purchase and surrender emission allowances, either for greenhouse gas emissions resulting from our operations (e.g., compressor stations) or from the combustion of fuels (e.g., natural gas or NGLs) that we process.

Also, as a result of the United States Supreme Court’s decision on April 2, 2007 in Massachusetts, et al.v. EPA, EPA was required to determine whether greenhouse gas emissions posed an endangerment to human health and the environment and whether emissions from mobile sources, such as cars and trucks contributed to that endangerment. On December 7, 2009, the EPA announced its findings that emissions of greenhouse gases present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere causing other climatic changes and that mobile sources are contributing to such endangerment. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In late September 2009, EPA proposed two sets of regulations in anticipation of finalizing its endangerment finding: one to reduce emissions of greenhouse gases from motor vehicles and the other to control emissions of greenhouse gases from stationary sources. Although the motor vehicle rules are expected to be adopted in March 2010, it may take EPA several years to impose regulations limiting emissions of greenhouse gases from stationary sources. In addition, on September 22, 2009, the EPA

 

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issued a final rule requiring the annual reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including NGL fractionators and local natural gas distribution companies. Any federal greenhouse gas legislation is expected to prevent EPA from regulating greenhouse gases under existing Clean Air Act regulatory programs to some extent, but if Congress fails to pass greenhouse gas legislation, the EPA is expected to continue its announced greenhouse gas regulatory actions under the Clean Air Act. Any limitation on emissions of greenhouse gases from our equipment and operations or the requirement that we obtain allowances for such emissions, as well as the NGLs that we produce, could require us to incur significant costs to reduce emissions of greenhouse gases associated with our operations or acquire allowances at the prevailing rates in the marketplace.

Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities from powerful winds or rising waters, or increased costs for insurance. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our propane and natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience substantially colder temperatures than their historical averages. As a result, it is difficult to predict how the market for our fuels would be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

Any reduction in the capacity of, or the allocations to, ETP’s shippers in interconnecting third-party pipelines could cause a reduction of volumes transported in ETP’s pipelines, which would adversely affect ETP’s revenues and cash flow.

Users of ETP’s pipelines are dependent upon connections to and from third-party pipelines to receive and deliver natural gas and NGLs. Any reduction in the capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes being transported in ETP’s pipelines. Similarly, if additional shippers begin transporting volumes of natural gas and NGLs over interconnecting pipelines, the allocations to existing shippers in these pipelines would be reduced, which could also reduce volumes transported in ETP’s pipelines. Any reduction in volumes transported in ETP’s pipelines would adversely affect its revenues and cash flow.

ETP may be impacted by competition from other midstream, transportation and storage companies and propane companies.

ETP experiences competition in all of its markets. ETP’s 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 its transportation pipeline systems. ETP’s competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas. The Southeast Texas System competes with natural gas gathering and processing systems owned by DCP Midstream, LLC. The North Texas System competes with Crosstex North Texas Gathering, LP and Devon Gas Services, LP for gathering and processing. The East Texas pipeline competes with other natural gas transportation pipelines that serve the Bossier Sands area in east Texas and the Barnett Shale region in north Texas. The ET Fuel System and the Oasis pipeline compete with a number of other natural gas pipelines, including interstate and intrastate pipelines that link the Waha Hub. The ET Fuel System competes with other natural gas transportation pipelines serving the Dallas/Ft. Worth area and other pipelines that serve the east central Texas and south Texas markets. Pipelines that ETP competes with in these areas include those owned by Atmos Energy Corporation, Enterprise Products Partners, L.P. and Enbridge, Inc. Some of ETP’s competitors may have greater financial resources and access to larger natural gas supplies than it does.

 

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The acquisitions of the HPL System and the Transwestern pipeline increased the number of interstate pipelines and natural gas markets to which ETP has access and expanded its principal areas of competition to areas such as southeast Texas and the Texas Gulf Coast. As a result of ETP’s expanded market presence and diversification, ETP faces additional competitors, such as major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas, which may have greater financial resources and access to larger natural gas supplies than ETP does.

The Transwestern pipeline and the Midcontinent Express pipeline (and upon completion the Fayetteville Express and Tiger pipelines) compete with other interstate and intrastate pipeline companies in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service, access to sources of supply and the flexibility and reliability of service. Natural gas competes with other forms of energy available to our customers and end-users, including for example, electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the capability to convert to alternate fuels and other factors, including weather and natural gas storage levels, affect the levels of natural gas transportation volumes in the areas served by our pipelines.

ETP’s propane business competes with a number of large national and regional propane companies and several thousand small independent propane companies. Because of the relatively low barriers to entry into the retail propane market, there is potential for small independent propane retailers, as well as other companies that may not currently be engaged in retail propane distribution, to compete with ETP’s retail outlets. As a result, ETP is always subject to the risk of additional competition in the future. Generally, warmer-than-normal weather further intensifies competition. Most of ETP’s retail propane branch locations compete with several other marketers or distributors in their service areas. The principal factors influencing competition with other retail propane marketers are:

 

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price,

 

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reliability and quality of service,

 

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responsiveness to customer needs,

 

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safety concerns,

 

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long-standing customer relationships,

 

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the inconvenience of switching tanks and suppliers, and

 

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the lack of growth in the industry.

The inability to continue to access tribal lands could adversely affect Transwestern’s ability to operate its pipeline system and the inability to recover the cost of right-of-way grants on tribal lands could adversely affect its financial results.

Transwestern’s ability to operate its pipeline system on certain lands held in trust by the United States for the benefit of a Native American Tribe, which we refer to as tribal lands, will depend on its success in maintaining existing rights-of-way and obtaining new rights-of-way on those tribal lands. Securing extensions of existing and any additional rights-of-way is also critical to Transwestern’s ability to pursue expansion projects. We cannot provide any assurance that Transwestern will be able to acquire new rights-of-way on tribal lands or maintain access to existing rights-of-way upon the expiration of the current grants. Our financial position could be adversely affected if the costs of new or extended right-of-way grants cannot be recovered in rates. Transwestern’s existing right-of-way agreements with the Navajo Nation, Southern Ute, Pueblo of Laguna and Fort Mojave tribes extend through November 2029, September 2020, December 2022 and April 2019, respectively.

 

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ETP may be unable to bypass the processing plants, which could expose it to the risk of unfavorable processing margins.

Because of ETP’s ownership of the Oasis pipeline and ET Fuel System, it can generally elect to bypass ETP’s processing plants when processing margins are unfavorable and instead deliver pipeline-quality gas by blending rich gas from the gathering systems with lean gas transported on the Oasis pipeline and ET Fuel System. In some circumstances, such as when ETP does not have a sufficient amount of lean gas to blend with the volume of rich gas that it receives at the processing plant, ETP may have to process the rich gas. If ETP has to process when processing margins are unfavorable, its results of operations will be adversely affected.

ETP may be unable to retain existing customers or secure new customers, which would reduce its revenues and limit its future profitability.

The renewal or replacement of existing contracts with ETP’s customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond its control, including competition from other pipelines, and the price of, and demand for, natural gas in the markets ETP serves.

For ETP’s year ended December 31, 2009, approximately 26% of its sales of natural gas was to industrial end-users and utilities. As a consequence of the increase in competition in the industry and volatility of natural gas prices, end-users and utilities are increasingly reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are many companies of greatly varying size and financial capacity that compete with ETP in the marketing of natural gas, ETP often competes in the end-user and utilities markets primarily on the basis of price. The inability of ETP’s management to renew or replace its current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on ETP’s profitability.

ETP’s storage business may depend on neighboring pipelines to transport natural gas.

To obtain natural gas, ETP’s storage business depends on the pipelines to which they have access. Many of these pipelines are owned by parties not affiliated with ETP. Any interruption of service on those pipelines or adverse change in their terms and conditions of service could have a material adverse effect on ETP’s ability, and the ability of its customers, to transport natural gas to and from its facilities and a corresponding material adverse effect on ETP’s storage revenues. In addition, the rates charged by those interconnected pipelines for transportation to and from ETP’s facilities affect the utilization and value of its storage services. Significant changes in the rates charged by those pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on ETP’s storage revenues.

ETP’s pipeline integrity program may cause it to incur significant costs and liabilities.

ETP’s 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. Based on the results of ETP’s current pipeline integrity testing programs, ETP estimates that compliance with these federal regulations and analogous state pipeline integrity requirements will result in capital costs of $20.5 million and operating and maintenance costs of $20.4 million over the course of the next year. For the years ended December 31, 2009 and 2008, $31.4 million and $23.3 million, respectively, of capital costs and $18.5 million and $13.1 million, respectively, of operating and maintenance costs have been

 

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incurred for pipeline integrity testing. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause ETP to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines.

Since weather conditions may adversely affect demand for propane, ETP’s financial conditions may be vulnerable to warm winters.

Weather conditions have a significant impact on the demand for propane for heating purposes because the majority of ETP’s customers rely heavily on propane as a heating fuel. Typically, ETP sells approximately two-thirds of its retail propane volume during the peak-heating season of October through March. ETP’s results of operations can be adversely affected by warmer winter weather, which results in lower sales volumes. In addition, to the extent that warm weather or other factors adversely affect ETP’s operating and financial results, its access to capital and its acquisition activities may be limited. Variations in weather in one or more of the regions where ETP operates can significantly affect the total volume of propane that ETP sells and the profits realized on these sales. Agricultural demand for propane may also be affected by weather, including unseasonably cold or hot periods or dry weather conditions that impact agricultural operations.

A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail ETP’s operations and otherwise materially adversely affect its cash flow and, accordingly, affect the market price of its Common Units.

Some of ETP’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 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 that deliver natural gas or other products to ETP are damaged by severe weather or any other disaster, accident, catastrophe or event, ETP’s operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply ETP’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 operations, or which causes it to make significant expenditures not covered by insurance, could reduce ETP’s cash available for paying distributions to its Unitholders, including us, and accordingly, adversely affect the market price of its Common Units.

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 may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If ETP were to incur a significant liability for which it was not fully insured, it could have a material adverse effect on ETP’s financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

Terrorist attacks aimed at ETP’s facilities could adversely affect its business, results of operations, cash flows and financial condition.

Since the September 11, 2001 terrorist attacks on the United States, the United States government has issued warnings that energy assets, including the nation’s pipeline infrastructure, may be the future target of terrorist organizations. Any terrorist attack on ETP’s facilities or pipelines or those of its customers could have a material adverse effect on ETP’s business.

 

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Sudden and sharp propane price increases that cannot be passed on to customers may adversely affect ETP’s profit margins.

The propane industry is a “margin-based” business in which gross profits depend on the excess of sales prices over supply costs. As a result, ETP’s profitability is sensitive to changes in energy prices, and in particular, changes in wholesale prices of propane. When there are sudden and sharp increases in the wholesale cost of propane, ETP may be unable to pass on these increases to its customers through retail or wholesale prices. Propane is a commodity and the price ETP pays for it can fluctuate significantly in response to changes in supply or other market conditions over which ETP has no control. In addition, the timing of cost pass-throughs can significantly affect margins. Sudden and extended wholesale price increases could reduce ETP’s gross profits and could, if continued over an extended period of time, reduce demand by encouraging ETP’s retail customers to conserve their propane usage or convert to alternative energy sources.

ETP’s results of operations could be negatively impacted by price and inventory risk related to its propane business and management of these risks.

ETP generally attempts to minimize its cost and inventory risk related to its propane business by purchasing propane on a short-term basis under supply contracts that typically have a one-year term and at a cost that fluctuates based on the prevailing market prices at major delivery points. In order to help ensure adequate supply sources are available during periods of high demand, ETP may purchase large volumes of propane during periods of low demand or low price, which generally occur during the summer months, for storage in its facilities, at major storage facilities owned by third parties or for future delivery. This strategy may not be effective in limiting ETP’s cost and inventory risks if, for example, market, weather or other conditions prevent or allocate the delivery of physical product during periods of peak demand. If the market price falls below the cost at which ETP made such purchases, it could adversely affect its profits.

Some of ETP’s propane sales are pursuant to commitments at fixed prices. To mitigate the price risk related to ETP’s anticipated sales volumes under the commitments, ETP may purchase and store physical product and/or enter into fixed price over-the-counter energy commodity forward contracts and options. Generally, over-the-counter energy commodity forward contracts have terms of less than one year. ETP enters into such contracts and exercises such options at volume levels that it believes are necessary to manage these commitments. The risk management of ETP’s inventory and contracts for the future purchase of product could impair its profitability if the customers do not fulfill their obligations.

ETP also engages in other trading activities, and may enter into other types of over-the-counter energy commodity forward contracts and options. These trading activities are based on ETP management’s estimates of future events and prices and are intended to generate a profit. However, if those estimates are incorrect or other market events outside of ETP’s control occur, such activities could generate a loss in future periods and potentially impair its profitability.

ETP is dependent on its principal propane suppliers, which increases the risk of an interruption in supply.

During 2009, ETP purchased approximately 50.3%, 14.3% and 15.1% of its propane from Enterprise, Targa and M.P. Oils, Ltd., respectively. Enterprise is a subsidiary of Enterprise GP, an entity that owns approximately 17.6% of ETE’s outstanding Common Units and a 40.6% non-controlling equity interest in our General Partner. Titan purchases the majority of its propane from Enterprise pursuant to an agreement that expires in 2010 and contains renewal and extension options. If supplies from these sources were interrupted, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and, at least on a short-term basis, margins could be adversely affected. Supply from Canada is subject to the additional risk of disruption associated with foreign trade such as trade restrictions, shipping delays and political, regulatory and economic instability.

 

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Historically, a substantial portion of the propane that ETP purchases originated from one of the industry’s major markets located in Mt. Belvieu, Texas and has been shipped to ETP through major common carrier pipelines. Any significant interruption in the service at Mt. Belvieu or other major market points, or on the common carrier pipelines ETP uses, would adversely affect its ability to obtain propane.

Competition from alternative energy sources may cause ETP to lose propane customers, thereby reducing its revenues.

Competition in ETP’s propane business from alternative energy sources has been increasing as a result of reduced regulation of many utilities. Propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because natural gas is a less expensive source of energy than propane. The gradual expansion of natural gas distribution systems and the availability of natural gas in many areas that previously depended upon propane could cause ETP to lose customers, thereby reducing its revenues. Fuel oil also competes with propane and is generally less expensive than propane. In addition, the successful development and increasing usage of alternative energy sources could adversely affect ETP’s operations.

Energy efficiency and technological advances may affect the demand for propane and adversely affect ETP’s operating results.

The national trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, has decreased the demand for propane by retail customers. Stricter conservation measures in the future or technological advances in heating, conservation, energy generation or other devices could adversely affect ETP’s operations.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us or ETP as a corporation for federal income tax purposes or if we 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 investment in ETP depends largely on ETP being treated as a partnership for federal income tax purposes.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. 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. Distributions to Unitholders would generally be taxed again as corporate distributions, and none of our income, gains, losses or deductions would flow through to Unitholders. Because a tax would then be imposed upon us as a corporation, our cash available for distribution to Unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the Unitholders, likely causing a substantial reduction in the value of our Common Units.

If ETP were treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate. Distributions to us would generally be taxed again as corporate distributions, and no income, gains, losses, deduction or credits would flow through to us. As a result, there would be a material reduction in our anticipated cash flow, likely causing a substantial reduction in the value of our units.

 

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Current law may change, causing us or ETP to be treated as a corporation for federal income tax purposes or otherwise subjecting us or ETP to entity-level taxation. For example, members of Congress have recently considered substantive changes to the existing federal income tax laws that would have affected certain publicly traded partnerships. Specifically, federal income tax legislation has been considered that would have eliminated partnership tax treatment for certain publicly traded partnerships and recharacterizes certain types of income received from partnerships. We or ETP are unable to predict whether any of these changes, or other proposals, will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our or ETP’s Common Units.

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

The tax treatment of our structure is subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The U.S. federal income tax treatment of Unitholders depends in some instances on determinations of fact and interpretations of complex provisions of U.S. federal income tax law. The U.S. federal income tax rules are constantly under review by persons involved in the legislative process, the IRS, and the U.S. Treasury Department, frequently resulting in revised interpretations of established concepts, statutory changes, revisions to Treasury Regulations and other modifications and interpretations. The present U.S. federal income tax treatment of an investment in our Common Units may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation (referred to as the “Qualifying Income Exception”), affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our Common Units. For example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Internal Revenue Code section 7704(d). It is possible that these efforts could result in changes to the existing U.S. federal tax laws that affect publicly traded partnerships, including us. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our Common Units.

If the IRS contests the federal income tax positions we or ETP takes, the market for our Common Units or ETP 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 ETP 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 ETP take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we or ETP take. A court may not agree with some or all of the positions we or ETP take. Any contest with the IRS may materially and adversely impact the market for our Common Units or ETP’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 ETP, and therefore indirectly by us, as a Unitholder and as the owner of the general partner of ETP, reducing the cash available for distribution to our Unitholders.

Unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our Unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, Unitholders will be required to pay any federal income taxes and,

 

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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. In such case, Unitholders would still be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income regardless of the amount, if any, of any cash distributions they receive from us.

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 tax basis in those units, even if the price received is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a Unitholder’s share of our nonrecourse liabilities, if a Unitholder sells units, the Unitholders may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning Common Units that may result in adverse tax consequences to them.

Investment in Common Units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs) and non-U.S. persons raises 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, at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal income tax returns and generally pay tax on their share of our taxable income.

We treat each purchaser of Common Units as having the same tax benefits without regard to the actual Common Units purchased. The IRS may challenge this treatment, which could result in a Unitholder owing more tax and may adversely affect the value of the Common Units.

The IRS may challenge the manner in which we calculate our Unitholder’s basis adjustment under Section 743(b) of the Internal Revenue Code. If so, because neither we nor a Unitholder can identify the units to which this issue relates once the initial holder has traded them, the IRS may assert adjustments to all Unitholders selling units within the period under audit as if all Unitholders owned such units.

Any position we take that is inconsistent with applicable Treasury Regulations may have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our Unitholders.

A successful IRS challenge to this position or other positions we may take could adversely affect the amount of taxable income or loss allocated to our Unitholders. It also could affect the gain from a Unitholder’s sale of Common Units and could have a negative impact on the value of the Common Units or result in audit adjustments to our Unitholders’ tax returns without the benefit of additional deductions. Moreover, because one of our subsidiaries that is organized as a C corporation for federal income tax purposes owns units in us, a successful IRS challenge could result in this subsidiary having more tax liability than we anticipate and, therefore, reduce the cash available for distribution to our partnership and, in turn, to our Unitholders.

 

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

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Although publicly traded partnerships are entitled to rely on these proposed Treasury Regulations, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued.

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

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

ETP has adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between us and the public Unitholders of ETP. The IRS may challenge this treatment, which could adversely affect the value of ETP’s Common Units and our Common Units.

When we or ETP issue additional units or engage in certain other transactions, ETP determines the fair market value of its assets and allocates any unrealized gain or loss attributable to such assets to the capital accounts of ETP’s Unitholders and us. Although ETP may from time to time consult with professional appraisers regarding valuation matters, including the valuation of its assets, ETP makes many of the fair market value estimates of its assets itself using a methodology based on the market value of its Common Units as a means to measure the fair market value of its assets. ETP’s methodology may be viewed as understating the value of ETP’s assets. In that case, there may be a shift of income, gain, loss and deduction between certain ETP Unitholders and us, which may be unfavorable to such ETP 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 tangible assets and a lesser portion allocated to ETP’s intangible assets. The IRS may challenge ETP’s valuation methods, or our or ETP’s allocation of Section 743(b) adjustment attributable to ETP’s tangible and intangible assets, and allocations of income, gain, loss and deduction between us and certain of ETP’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 or the ETP Unitholders. It also could affect the amount of gain on the sale of Common Units by our Unitholders or ETP’s Unitholders and could have a negative impact on the value of our Common Units or those of ETP or result in audit adjustments to the tax returns of our or ETP’s Unitholders without the benefit of additional deductions.

 

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

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in our filing two tax returns for one fiscal year and may result in a significant 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 his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for tax purposes. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred.

Unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our Common Units.

In addition to federal income taxes, the Unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or ETP conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

 

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ITEM 2. PROPERTIES

Substantially all of our pipelines, which are described in Item 1, 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. We 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. We also own and operate three natural gas storage facilities, including the Bammel facility, and own or lease other natural gas treating and conditioning facilities in connection with our midstream operations.

We own substantially all of the bulk storage facilities at our customer service locations for our propane operations and have entered into long-term leases for those that we do not own. We believe that the increasing difficulty associated with obtaining permits for new propane distribution locations makes our high level of site ownership and control a competitive advantage. We own approximately 50.9 million gallons of above-ground storage capacity at our various propane plant sites and have leased an aggregate of approximately 15.0 million gallons of underground storage facilities in Michigan, Arizona, New Mexico and Texas and smaller storage facilities in other locations. We do not own or operate any underground propane storage facilities (excluding customer and local distribution tanks) or propane pipeline transportation assets (other than local delivery systems).

Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances that will be transferred to us will require the consent of the current landowner to transfer these rights, which in some instances is a governmental entity. We believe that we have obtained or will obtain sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business in all material respects. With respect to any consents, permits or authorizations that have not been obtained, we believe that these consents, permits or authorizations will be obtained, or that the failure to obtain these consents, permits or authorizations will have no material adverse effect on the operation of our business.

We own an office building for our executive office in Dallas, Texas, and office buildings in Helena, Montana and San Antonio, Texas. We also own a field office building in Fruita, Colorado and lease office facilities in Houston, Texas, Florence, Kentucky, Tulsa, Oklahoma, Wexford, Pennsylvania, Bridgeport, West Virginia and Denver, Colorado. 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.

The transportation of propane requires specialized equipment. The trucks and railroad tank cars used for this purpose carry specialized steel tanks that maintain the propane in a liquefied state. As of December 31, 2009, we utilized approximately 172 transport truck tractors, 275 transport trailers, 19 railroad tank cars, 2,000 bobtails and 3,154 other delivery and service vehicles, all of which we own. As of December 31, 2009, we owned approximately 1,200,000 customer storage tanks with typical capacities of 120 to 1,000 gallons that are leased or available for lease to customers. HOLP’s customer storage tanks are pledged as collateral to secure the obligations of HOLP to its banks and the holders of its notes.

We utilize a variety of trademarks and trade names in our propane operations that we own or have secured the right to use, including “Heritage Propane”, “Titan Propane,” and “Relationships Matter.” These trademarks and trade names have been registered or are pending registration before the United States Patent and Trademark Office or the various jurisdictions in which the trademarks or trade names are used. We believe that our strategy of retaining the names of the companies we have acquired has maintained the local identification of these companies and has been important to the continued success of these businesses. Some of our most significant trade names include Balgas, Bi-State Propane, Blue Flame Gas of Charleston, Blue Flame Gas of Mt. Pleasant, Blue Flame Gas, Carolane Propane Gas, Gas Service Company, EnergyNorth Propane, Gibson Propane, Guilford

 

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Gas, Holton’s L.P. Gas, Ikard & Newsom, Northern Energy, Sawyer Gas, ProFlame, Rural Bottled Gas and Appliance, ServiGas, and V-1 Propane, Coast Gas, Empiregas, Flame Propane, Graves Propane, Heritage Propane Express and Synergy Gas. We regard our trademarks, trade names and other proprietary rights as valuable assets and believe that they have significant value in the marketing of our products.

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.

ITEM 3. LEGAL PROCEEDINGS

We are not aware of any material legal or governmental proceedings against us or our Operating Companies, or contemplated to be brought against us or our Operating Companies, under the various environmental protection statutes to which they are subject, except for the December 21, 2009 Compliance Order on Consent issued by the Colorado Department of Public Health and Environment Air Pollution Control Division, as discussed above under “Item 1, Business – Environmental Matters.”

For a description of legal proceedings, see note 11 to our consolidated financial statements.

 

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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 the 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 Common Unit, as reported on the NYSE Composite Transaction Tape, and the amount of cash distributions paid per Common Unit since the Parent Company’s initial public offering (“IPO”) in February 2006.

 

     Price Range    Cash
Distribution (1)
     High    Low   

Fiscal Year 2009

              

Fourth Quarter Ended December 31, 2009

       $     31.00        $     26.88        $     0.5400

Third Quarter Ended September 30, 2009

     30.46      24.25      0.5350

Second Quarter Ended June 30, 2009

     27.14      20.66      0.5350

First Quarter Ended March 31, 2009

     22.43      15.90      0.5250

Fiscal Year 2008

              

Fourth Quarter Ended December 31, 2008

       $ 22.35        $ 12.75        $ 0.5100

Third Quarter Ended September 30, 2008

     30.31      19.00      0.4800

Second Quarter Ended June 30, 2008

     35.02      28.47      0.4800

First Quarter Ended March 31, 2008

     35.26      26.99      0.4400

 

(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” for a discussion of our policy regarding the payment of distributions.

Description of Units

As of February 16, 2010, there were approximately 39,600 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, 2009, Common Units represent an aggregate 99.7% limited partner interest in us. Our General Partner owns an aggregate 0.31% General Partner interest in us. Our Common Units are registered under the Exchange Act, as amended, 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:

 

Ÿ  

provide for the proper conduct of its business;

 

Ÿ  

comply with applicable law and/or debt instrument or other agreement; and

 

Ÿ  

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 7 to our consolidated financial statements.

Recent Sales of Unregistered Securities

None.

Issuer Purchases of Equity Securities

None.

 

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ITEM 6.  SELECTED FINANCIAL DATA

Currently, the Parent Company has no separate operating activities apart from those conducted by the Operating Companies. The table below reflects the consolidated operations of the Parent Company including the operations of ETP and its consolidated subsidiaries, except as indicated below.

In November 2007, we changed our fiscal year end from August 31 to December 31 and, in connection with such change, we have reported financial results for a four-month transition period ended December 31, 2007.

The selected financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and the accompanying notes thereto included elsewhere in this report. The amounts in the table below, except per unit data, are in thousands.

 

    Years Ended December 31,     Four Months
Ended
December 31,

2007
    Years Ended August 31,  
Statement of Operations Data:   2009     2008       2007     2006     2005  

Revenues:

           

Intrastate transportation and storage segment

  $         2,391,544      $         5,634,604      $         1,254,401      $         3,915,932      $         5,013,224      $         2,608,108   

Interstate transportation segment (a)

    270,213        244,224        76,000        178,663        -        -   

Midstream segment

    2,441,160        5,342,393        1,166,313        2,853,496        4,223,544        3,246,772   

Retail propane and other retail propane related segment

    1,292,583        1,624,010        511,258        1,284,867        879,556        709,473   

All other

    21,665        16,201        5,892        121,278        102,028        75,700   

Eliminations

    (999,870     (3,568,065     (664,522     (1,562,199     (2,359,256     (471,255
                                               

Total revenues

    5,417,295        9,293,367        2,349,342        6,792,037        7,859,096        6,168,798   

Gross margin

    2,295,239        2,355,287        675,688        1,713,831        1,290,780        787,283   

Depreciation and amortization

    325,024        274,372        75,406        191,383        129,636        105,751   

Operating income

    1,110,398        1,098,903        316,651        809,336        575,540        297,921   

Interest expense, net of interest capitalized

    468,420        357,541        103,375        279,986        150,646        101,061   

Income from continuing operations before income tax expense

    707,100        683,562        192,758        563,359        433,907        201,795   

Income tax expense (b)

    9,229        3,808        9,949        11,391        23,015        4,397   

Income from continuing operations (c)

    697,871        679,754        182,809        551,968        410,892        197,398   

Net income attributable to noncontrolling
interest (c)

    255,398        304,710        90,132        232,608        303,752        96,946   

Basic income from continuing operations per limited partner unit (d)

    1.98        1.68        0.41        1.56        0.80        0.89   

Diluted income from continuing operations per limited partner unit (d)

    1.98        1.68        0.41        1.55        0.79        0.75   

Cash distribution per unit

    2.14        1.91        0.55        1.46        2.56        2.66   

Balance Sheet Data (at period end):

           

Current assets

    1,267,959        1,180,995        1,403,796        1,050,578        1,302,736        1,453,730   

Total assets

    12,160,509        11,069,902        9,462,094        8,183,089        5,924,141        4,905,672   

Current liabilities

    889,745        1,208,921        1,241,433        932,815        1,020,787        1,244,785   

Long-term debt, less current maturities

    7,750,998        7,190,357        5,870,106        5,198,676        3,205,646        2,275,965   

Equity

    3,220,251        2,339,316        2,091,156        1,835,300        1,484,878        1,123,998   

Other Financial Data:

           

Cash flow provided by operating activities

    723,461        1,143,720        208,635        1,006,320        502,928        155,086   

Cash flow used in investing activities

    (1,345,756     (2,015,585     (995,943     (2,158,090     (1,244,406     (1,131,117

Cash flow provided by financing activities

    598,587        907,331        766,515        1,202,916        734,223        926,638   

Capital expenditures:

           

Maintenance (accrual basis)

    102,652        140,968        48,998        89,226        51,826        41,054   

Growth (accrual basis)

    530,333        1,921,679        604,371        998,075        677,861        155,405   

Cash (received in) paid for acquisitions

    (30,367     84,783        337,092        90,695        586,185        1,131,844   

 

(a) Our interstate transportation operations began in fiscal 2007 with the acquisition of Transwestern pipeline.

 

(b) As a partnership, we are generally not subject to income taxes. However, our subsidiaries, Oasis Pipe Line Company, Heritage Holdings, Heritage Service Corporation and Titan Propane Services, Inc. are corporations subject to income taxes.

 

(c) On January 1, 2009, we adopted Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements - An Amendment of ARB No. 51, now incorporated into ASC 810-10. Certain adjustments have been made to prior period information to conform to current period presentation related to the adoption. See Note 2 to our consolidated financial statements for further discussion.

 

(d) See Note 5 to our consolidated financial statements for a discussion of the computation of income per limited partner unit.

 

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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 IPO of 24,150,000 Common Units 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 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,” included in this report.

Unless the context requires otherwise, references to “we,” “us,” “our,” and “ETE” shall mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. (“ETP”), Energy Transfer Partners G.P., L.P. (“ETP GP”), the General Partner of ETP, and ETP GP’s General Partner, Energy Transfer Partners, L.L.C. (“ETP LLC”). References to “the Parent Company” shall mean Energy Transfer Equity, L.P. on a stand-alone basis.

Overview

Currently, our business operations are conducted only through ETP’s Operating Companies, ETC OLP, a Texas limited partnership engaged in midstream and intrastate transportation and natural gas storage operations, Energy Transfer Interstate Holdings, LLC (“ET Interstate”), the parent company of Transwestern Pipeline Company, LLC (“Transwestern”), a Delaware limited liability company engaged in interstate transportation of natural gas, and ETC Midcontinent Express Pipeline, LLC (“ETC MEP” or “MEP”), a Delaware limited liability company engaged in interstate transportation of natural gas, and HOLP and Titan, both Delaware limited partnerships engaged in retail propane operations.

Parent Company – Energy Transfer Equity, L.P.

The principal sources of cash flow for the Parent Company are distributions it receives from its direct and indirect investments in limited and general partner interests of ETP. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service and distributions to its partners. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of ETP or the Operating Companies.

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 cash distributions over time by pursuing a business strategy that is currently focused on growing our natural gas midstream and intrastate transportation and storage businesses (including transportation, gathering, compression, treating, processing, storage and marketing) and our propane business through, among other things, pursuing certain construction and expansion opportunities relating to our existing infrastructure and acquiring certain additional businesses or assets. The actual amounts of cash that we will have available for distribution will primarily depend on the amount of cash we generate from operations.

During the past several years, we have been successful in completing several transactions that have been accretive to our Unitholders. First and foremost was the completion of the Energy Transfer Transactions, which

 

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caused the combination of the retail propane operations of Heritage Propane Partners, L.P. and the midstream and intrastate transportation and storage operations of ETC OLP in January 2004. Subsequent to the combination, we have made numerous significant acquisitions in both our natural gas and propane operations, most notably the following:

 

Ÿ  

ET Fuel System in June 2004

 

Ÿ  

HPL System in January 2005

 

Ÿ  

Titan Propane in June 2006

 

Ÿ  

Transwestern in December 2006

 

Ÿ  

Canyon Gathering System in October 2007

We have also made, and are continuing to make, significant investments in internal growth projects, primarily the construction of pipelines, gathering systems and natural gas treating and processing plants, which we believe will provide additional cash flow to our Unitholders for years to come. In 2009, we completed several projects, including the Texas Independence Pipeline in August 2009. In January 2009, we completed our Southern Shale and Cleburne to Tolar pipeline projects. We also completed our Phoenix lateral pipeline in February 2009.

Our principal operations are conducted in the following segments:

 

Ÿ  

Intrastate transportation and storage - Revenue is principally generated from fees charged to customers to reserve firm capacity on or move gas through the pipeline on an interruptible basis. The fee structure consists of a monetary fee and/or fuel retention. Excess fuel retained after consumption is sold at market prices. Our HPL System generates revenue primarily from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies.

We generate fee-based revenue from our natural gas storage facilities by contracting with third parties for their use of our storage capacity. From time to time, we utilize our excess storage capacity to inject and hold natural gas in our Bammel storage facility to take advantage of contango markets, a term to describe a pricing environment when the price of natural gas is higher in the future than the current spot price. We use financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, we lock in a margin by purchasing gas in the spot market and entering a financial derivative to lock in the sale price. If we designate the related financial derivative as a fair value hedge for accounting purposes, we value the hedged natural gas inventory at current spot market prices whereas the financial derivative is valued using forward natural gas prices. As a result, under fair value hedge accounting, changes in the spread between forward natural gas prices and spot market prices result in unrealized gains or losses until the underlying physical gas is withdrawn and the related financial derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. If the spread narrows between the spot and forward prices, we will record unrealized gains or lower unrealized losses. If the spread widens, we will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges, so that we recognize in earnings the original locked in spread.

In addition to hedging our stored natural gas, we also use financial derivatives to lock in prices on a portion of our estimated volumes exposed to natural gas price risk within our intrastate transportation segment.

During 2009, we also entered into financial derivatives to lock in spreads on a portion of our transportation system’s open capacity. Margins earned on that open capacity are dependent on price differentials at different points on our system, generally from West Texas to East Texas. We account for these financial derivatives using mark-to-market accounting and the change in value of these derivatives are recorded in earnings. As of December 31, 2009, approximately 3.4% of our capacity is hedged.

 

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Ÿ  

Interstate transportation - Revenue is primarily generated by fees earned from natural gas transportation services and operational gas sales.

 

Ÿ  

Midstream - Revenue is principally dependent upon the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipelines as well as the level of natural gas and NGL prices.

In addition to fee-based contracts for gathering, treating and processing, we also have percent of proceeds and keep-whole contracts, which are subject to market pricing. For percent of proceeds contracts (which generally account for approximately 11% of total processed volumes), we retain a portion of the natural gas and NGLs processed as a fee. When natural gas and NGL pricing increase, the value of the percent we retain as a fee increases. Conversely, when prices of natural gas and NGL’s decrease, so does the value of the portion we retain as a fee. For keep-whole contracts (which account for approximately 24% of total processed volumes), we retain the difference between the price of NGLs and the cost of the gas to process it. In periods of high NGL prices relative to natural gas, our margins increase. During periods of low NGL prices relative to natural gas, our margins decrease or could be negative. In the event it is uneconomical to process this gas, we have the ability to bypass our processing plants to avoid negative margins that may occur from processing NGLs.

We conduct marketing operations in which we market the natural gas that flows through our 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 supply points 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.

 

Ÿ  

Retail propane and other retail propane related operations - Revenue is generated from the sale of propane and propane-related products and services.

Trends and Outlook

Economic forecasts indicate continued high storage levels combined with slow consumption growth are expected to keep natural gas prices from rising dramatically throughout 2010. We have mitigated much of the exposure to changing prices and demand within our operations. In our natural gas operations, a significant portion of our revenue continues to be derived from long-term fee-based arrangements, pursuant to which our customers pay us capacity reservation fees regardless of the volume of natural gas transported; however, we do recognize a portion of our revenue from fees based on actual volumes transported. In addition, we continue to evaluate and execute strategies to mitigate the impacts of changing prices. For example, during the second half of 2009, we began entering into hedges to lock in prices on a portion of our estimated volumes exposed to natural gas price risk within our intrastate transportation segment. These volumes include net retained fuel and a portion of volumes purchased at the wellhead from producers and sold at market prices. Approximately 79% of our estimated volumes exposed to natural gas price risk in 2010 is currently hedged.

With our liquid take-away capacity, we anticipate a slight increase in volumes of NGLs processed in 2010. We believe this will have a favorable impact on our fee-based business as producers will be motivated to take advantage of the favorable pricing.

ETP maintained its quarterly distributions per ETP Common Unit at a consistent rate, without increase, throughout 2009. Nevertheless, the distributions we received from ETP in 2009 increased through our ownership of the incentive distribution rights of ETP, as a result of ETP’s issuance of additional ETP Common Units. We were therefore able to increase the distributions that we paid per ETE Common Unit in 2009. Our ability to increase our distributions going forward will be dependent on ETP’s issuances of additional ETP Common Units and/or increases in its quarterly distribution per ETP Common Unit.

 

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We and ETP are continuing our pursuit of growth through construction of new assets, expansion of our existing assets and through strategic acquisitions. To that end, we currently expect to spend between $1.2 billion and $1.3 billion for growth capital expenditures on a consolidated basis in 2010. We believe that we have sufficient liquidity to fund our announced growth projects in 2010; furthermore, we believe that our current liquidity position would provide us the financial flexibility to pursue accretive acquisitions of various sizes.

Results of Operations

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 of this Form 10-K. For periods prior to 2009, certain prior period financial statement amounts have been reclassified to conform to the 2009 presentation. These changes had no impact on net income, with the exception of changes to the presentation of noncontrolling interest resulting from the adoption of Accounting Standards Codification 810-10-65, which resulted in the reclassification of minority interest expense to net income attributable to noncontrolling interest in our consolidated statement of operations.

In November 2007, we changed our fiscal year end to the calendar year. Thus, a new fiscal year began on January 1, 2008. We completed a four-month transition period that began September 1, 2007 and ended December 31, 2007 and filed a transition report on Form 10-Q for that period in February 2008. We subsequently filed audited financial statements for the four-month transition period on Form 8-K on March 19, 2008. The results of operations contained herein cover the calendar years ended December 31, 2009 and 2008, the four-month periods ended December 31, 2007 and 2006 and the fiscal year ended August 31, 2007.

We did not recast the financial data for the prior fiscal periods because the financial reporting processes in place at that time included certain procedures that were completed only on a quarterly basis. Consequently, to recast those periods would have been impractical and would not have been cost-justified. Comparability between periods is impacted primarily by weather, fluctuations in commodity prices, volumes of natural gas sold and transported, our hedging strategies and the use of financial instruments, trading activities, basis differences between market hubs and interest rates. We believe that the trends indicated by comparison of the results for the calendar years ended December 31, 2009 and 2008 are substantially similar to what is reflected in the information for the fiscal year ended August 31, 2007.

The comparability of our operations information is affected by the December 1, 2006 acquisition of Transwestern. The volumes and results of operations data for the four months ended December 31, 2007 include the interstate operations for the entire period. However, the volumes and results of operations for the four months ended December 31, 2006 include the interstate operations only from the acquisition date forward.

Historically, the comparability of our consolidated financial statements is affected by fluctuation in natural gas prices, mainly due to natural gas sales and purchases. Since certain activities involve the purchase and sale of natural gas primarily based on either first of month index prices, gas daily average prices or a combination of both, our gas sales and purchases tend to be higher when natural gas prices are high and our gas sales and purchases tend to be lower when natural gas prices are lower. However, a change in natural gas prices is only one of several elements that impact our overall margin. Other factors include, but are not limited to, volumetric changes, our hedging strategies and the use of financial instruments, fee-based revenues and basis differences between market hubs.

Due to the high level of market volatility experienced in 2008, as well as other business considerations, the Partnership ceased its trading of financial derivative instruments that are not offset by physical positions in July 2008. As a result, the Partnership will no longer have any material exposure to market risk from these activities. Trading activities resulted in net losses of approximately $26.2 million for the year ended December 31, 2008, net losses of approximately $2.3 million for the four-month transition period ended December 31, 2007, and net gains of approximately $2.2 million for the fiscal year ended August 31, 2007.

 

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The Parent Company currently has no separate operating activities apart from those conducted by ETP and its Operating Companies. The principal sources of cash flow for the Parent Company are its direct and indirect investments in the limited and general partner interests of ETP. The Parent Company results of operations reflect the ETE stand-alone results of operations for all periods presented below.

Year Ended December 31, 2009 Compared to the Year Ended December 31, 2008 (tabular dollar amounts are expressed in thousands)

Parent Company Only Results

The following table summarizes the key components of the stand-alone results of operations of the Parent Company for the periods indicated:

 

     Years Ended December 31,    Change  
     2009    2008   

Equity in earnings of affiliates

   $    526,383     $    551,835     $    (25,452

Selling, general and administrative expenses

   (4,970)    (6,453)    1,483   

Interest expense

   (74,049)    (91,822)    17,773   

Losses on non-hedged interest rate derivatives

   (5,620)    (77,435)    71,815   

Other, net

   79    (1,056)    1,135   

The following is a discussion of the highlights of the Parent Company’s stand-alone results of operations for the periods presented.

Equity in Earnings of Affiliates.  Equity in earnings of affiliates represents earnings of the Parent Company related to its investment in limited partner units of ETP, its ownership of ETP GP and its ownership of ETP LLC. The decrease in equity in earnings of affiliates was directly related to the changes in the ETP segment income described below.

Interest Expense.  For the three and nine month periods, the Parent Company interest expense decreased primarily due to a decrease in the LIBOR rate between the periods.

Gains (Losses) on Non-Hedged Interest Rate Derivatives.  The Parent Company has interest swaps that are not accounted for as hedges. Changes in the fair value of these swaps are recorded directly in earnings. The variable portion of these swaps is based on the three month LIBOR and its corresponding forward curve. Increases or decreases in gains (losses) on non-hedged interest rate derivatives are due to changes in these rates. We recorded unrealized losses on our interest rate swaps as a result of decreases in the relevant floating index rates during the periods presented.

 

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Consolidated Results

 

     Years Ended December 31,     Change  
     2009     2008    

Revenues

      $     5,417,295         $     9,293,367         $     (3,876,072

Cost of products sold

     3,122,056        6,938,080        (3,816,024
                        

Gross margin

     2,295,239        2,355,287        (60,048

Operating expenses

     680,893        781,831        (100,938

Depreciation and amortization

     325,024        274,372        50,652   

Selling, general and administrative

     178,924        200,181        (21,257
                        

Operating income

     1,110,398        1,098,903        11,495   

Interest expense, net of interest capitalized

     (468,420     (357,541     (110,879

Equity in earnings (losses) of affiliates

     20,597        (165     20,762   

Losses on disposal of assets

     (1,564     (1,303     (261

Gains (losses) on non-hedged interest rate derivatives

     33,619        (128,423     162,042   

Allowance for equity funds used during construction

     10,557        63,976        (53,419

Other, net

     1,913        8,115        (6,202

Income tax expense

     (9,229     (3,808     (5,421
                        

Net income

      $ 697,871         $ 679,754         $ 18,117   
                        

See the detailed discussion of revenues, costs of products sold, gross margin, operating expenses, and depreciation and amortization by operating segment below.

Interest Expense.  Interest expense increased principally due to higher levels of borrowings, which were used to finance growth capital expenditures primarily in our intrastate transportation and storage and interstate transportation segments, including capital contributions to our joint ventures.

Equity in Earnings (Losses) of Affiliates.  The increase in equity in earnings of affiliates between the periods was primarily attributable to earnings of MEP, which was placed in service in 2009. We recorded equity in earnings of MEP of $14.0 million during 2009.

Gains (Losses) on Non-Hedged Interest Rate Derivatives.  We had interest rate swaps with notional amounts totaling $2.13 billion outstanding at December 31, 2008, $625.0 million of which were settled or terminated during 2009. As of December 31, 2009, we have interest rate swaps outstanding with notional amounts totaling $1.50 billion. The losses during 2008 primarily relate to changes in the fair value of non-hedged interest rate swaps as a result of a sharp decline in the index rate, while the gains in 2009 resulted from increases in the index rate.

Allowance for Equity Funds Used During Construction.  The decrease in the allowance of equity funds used was due to the completion of the Phoenix project in February 2009.

Other Income, Net.  The decrease between the periods was primarily due to contributions in aid of construction, which exceeded our project costs during 2008.

Income Tax Expense.  As a partnership, we are generally not subject to income taxes. However, certain wholly-owned subsidiaries are corporations that are subject to income taxes. Income tax expense was higher in 2009 principally due to a tax benefit resulted from trading losses incurred by one of our corporate subsidiaries in 2008.

 

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Segment Operating Results

We evaluate segment performance based on operating income (either in total or by individual segment), which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.

For additional information regarding our business segments, see Item 1 and Notes 1 and 15 to our consolidated financial statements.

Operating income (loss) by segment is as follows:

 

     Years Ended December 31,    Change
     2009    2008   

Intrastate transportation and storage

     $ 618,500      $ 710,070      $ (91,570)

Interstate transportation

     138,233      124,676      13,557

Midstream

     136,790      162,471      (25,681)

Retail propane and other retail propane related

     229,229      114,564          114,665

All other

     (8,658)      (2,032)      (6,626)

Unallocated selling, general and administrative expenses

     (3,696)      (10,846)      7,150
                    

Operating income

     $     1,110,398      $     1,098,903      $ 11,495
                    

Unallocated Selling, General and Administrative Expenses.  Selling, general and administrative expenses are allocated monthly to the Operating Companies using the Modified Massachusetts Formula Calculation (“MMFC”). The expenses subject to allocation are based on estimated amounts and take into consideration actual expenses from previous months and known trends. The difference between the allocation and actual costs is adjusted in the following month, which results in over or under allocation of these costs due to timing differences.

Intrastate Transportation and Storage

 

     Years Ended December 31,    Change  
     2009    2008   

Natural gas MMBtu/d - transported

         12,254,168          11,187,327      1,066,841   

Natural gas MMBtu/d - sold

     969,601      1,389,781      (420,180

Revenues

      $ 2,391,544       $ 5,634,604       $ (3,243,060)   

Cost of products sold

     1,393,295      4,467,552          (3,074,257)   
                      

Gross margin

     998,249      1,167,052      (168,803)   

Operating expenses

     199,806      287,515      (87,709)   

Depreciation and amortization

     115,884      92,979      22,905   

Selling, general and administrative

     64,059      76,488      (12,429)   
                      

Segment operating income

      $ 618,500       $ 710,070       $ (91,570)   
                      

Volumes.  Overall volumes on our transportation pipelines were higher in 2009, principally due to the increased capacity of our pipeline system as a result of the completion of the Paris Loop, Maypearl to Malone pipeline, Carthage Loop, Southern Shale pipeline, Cleburne to Tolar pipeline, the Katy expansion and the Texas Independence Pipeline during 2008 and 2009. Natural gas sold decreased between the periods principally due to decreased demand from industrial end users and local distribution companies. Natural gas sold also includes net retained fuel, which is the excess of retained fuel less fuel consumed. Our net retained fuel volumes increased as compared to 2008.

 

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Gross Margin.  Intrastate transportation and storage gross margin decreased between periods primarily due to the following factors:

 

  Ÿ  

We recognized $639.0 million in margin from transportation fees during 2009, an increase of approximately $41.0 million compared to 2008, primarily due to increased volumes through our transportation pipelines from the additional capacity and additional demand fees added as a result of the additional capacity.

 

  Ÿ  

We recognized approximately $137.9 million in margin from retained fuel during 2009. Our fuel retention margin is directly impacted by changes in natural gas prices and transported volumes. We experienced an increase in natural gas volumes transported between periods; however, natural gas prices for retained fuel decreased from an average of $7.90/MMBtu during 2008 to $3.54/MMBtu during 2009, resulting in a decrease to the retention margin between the periods of $168.6 million.

 

  Ÿ  

We recognized $91.5 million in margin from the sale of natural gas in 2009, which was a reduction of $37.9 million compared to 2008, primarily due to the decrease in natural gas sold as a result of lower natural gas prices, lower price differentials, and lower demand from industrial end users and local distribution companies.

 

  Ÿ  

We recognized approximately $129.5 million in net storage margin during 2009, a decrease of $3.7 million from 2008. The activity resulting in the change was as follows:

 

  ¡  

We recognized margin of $98.6 million in 2009 from the sale of natural gas from our Bammel storage facility, a decrease of $92.9 million from 2008. During 2008 and 2009, we accounted for certain of our storage-related derivative instruments using mark-to-market accounting with changes in the value of these financial derivative instruments being recorded directly in earnings. During 2009, we recognized unrealized losses of $93.8 million from mark-to-market non-fair value hedge accounting adjustments; we recognized unrealized gains of $89.9 million in 2008. Additionally, we recognized realized gains of $168.8 million and $3.9 million from the settlement of derivative contracts during 2009 and 2008, respectively.

 

  ¡  

Beginning in April 2009, we elected fair value hedge accounting for certain storage-related transactions. We recognized net unrealized gains of $48.6 million as a result of fair value hedge accounting.

 

  ¡  

We also recognized $54.0 million and $69.5 million of non-cash lower of cost or market adjustments in 2009 and 2008, respectively.

 

  ¡  

We recognized margin of approximately $39.7 million during 2009 from our third-party fee-based storage revenue, an increase of $5.7 million compared to 2008.

 

  Ÿ  

Excluding the derivatives relating to storage activities discussed above, we recognized unrealized gains of $20.9 million in 2009 and unrealized losses of $10.1 million in 2008 on financial derivatives to mitigate price risk associated with transportation activities. These amounts are included in the margin from retained fuel and the sale of natural gas discussed above.

Operating Expenses.  Intrastate transportation and storage operating expenses decreased between the periods primarily due to a decrease in the cost of natural gas consumed of $93.1 million from $149.0 million in 2008 to $55.9 million in 2009. This decrease is principally due to both a decrease in consumption volumes and a decrease

 

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in natural gas prices as compared to the prior year. In addition, we experienced a decrease in electricity costs of approximately $12.9 million between the periods. Offsetting these decreases were increases in ad valorem taxes of $15.3 million, resulting from increased property values and additions, and increases in pipeline maintenance expenses of approximately $3.4 million.

Depreciation and Amortization.  Intrastate transportation and storage depreciation and amortization expense increased primarily due to the completion of pipeline expansion projects as noted above.

Selling, General and Administrative Expenses.  Intrastate transportation and storage selling, general and administrative expenses decreased between the periods primarily due to decreased employee-related costs (including allocated overhead expenses) of approximately $9.5 million and a decrease in professional fees of approximately $2.8 million.

Interstate Transportation

 

     Years Ended December 31,    Change  
     2009    2008   

Natural gas MMBtu/d -transported

         1,661,785          1,777,097          (115,312

Natural gas MMBtu/d - sold

     18,531      15,162      3,369   

Revenues

      $ 270,213       $ 244,224       $ 25,989   

Operating expenses

     59,343      56,906      2,437   

Depreciation and amortization

     48,297      37,790      10,507   

Selling, general and administrative

     24,340      24,852      (512
                      

Segment operating income

      $ 138,233       $ 124,676       $ 13,557   
                      

Interstate transportation segment table does not include the natural gas volumes transported or sold, or the operating income of our interstate pipeline joint ventures, which is reflected below operating income in our consolidated statement of operations. During 2009, we recognized $14.0 million in equity in earnings related to our 50% joint venture investment in MEP.

Volumes.  Transported volumes decreased as compared to 2008 primarily as a result of less favorable pricing differentials between the San Juan and Permian Basins during the period.

Revenues.  Interstate transportation revenues increased between the periods by approximately $42.5 million primarily as a result of the completion of the Phoenix project in February 2009. This increase was partially offset by a $16.5 million decrease in operational gas sales primarily due to decreased natural gas prices between the periods.

Operating Expenses.  Interstate operating expenses increased between the periods due to an increase in ad valorem taxes of approximately $4.2 million resulting from increased property values related to the Phoenix pipeline expansion. The increase in ad valorem taxes was partially offset by a net decrease of $1.4 million in operating expenses primarily due to lower electric demand costs, professional fees and gas imbalance activities.

Depreciation and Amortization.  Interstate depreciation and amortization expense increased by $10.5 million between the periods primarily due to incremental depreciation associated with the completion of the San Juan lateral and Phoenix projects.

 

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Midstream

 

     Years Ended December 31,    Change  
     2009    2008   

Natural gas MMBtu/d - sold

     1,080,552      1,269,724      (189,172

NGLs Bbls/d - sold

     39,064      25,939      13,125   

Revenues

      $     2,441,160      $     5,342,393       $ (2,901,233

Cost of products sold

     2,116,279      4,986,495          (2,870,216
                      

Gross margin

     324,881      355,898      (31,017

Operating expenses

     68,989      82,872      (13,883

Depreciation and amortization

     74,787      63,287      11,500   

Selling, general and administrative

     44,315      47,268      (2,953
                      

Segment operating income

      $ 136,790       $ 162,471       $ (25,681
                      

Volumes.  The decrease in the volumes of natural gas sold was primarily due to less favorable marketing activities as compared to 2008, and the increase in NGL volumes sold was due to increased capacity to delivery NGL volumes at our Godley plant starting in January 2009.

Gross Margin.  Midstream gross margin decreased between the periods primarily due to the following factors:

 

  Ÿ  

We recognized $141.0 million in processing margin, a decrease of $53.9 million compared to the prior year. The decrease in margin was primarily due to less favorable processing conditions during the period as compared to 2008.

 

  Ÿ  

We recognized $170.2 million in gathering, processing and treating fee-based revenues, an increase of $6.4 million compared to the prior year. The increase in feed-based revenue, was principally a result of more take away capacity at our Godley plant that allowed for an increase in fee-based processing volumes.

 

  Ÿ  

We recognized $13.6 million in margin from our marketing activities during 2009. This was a favorable change between the periods of approximately $16.5 million primarily due to losses recognized from trading activities during 2008. As noted above, we ceased these trading activities in the latter part of 2008.

 

  Ÿ  

Included in the marketing activity discussed above are unrealized gains of $8.7 million and $1.3 million in 2009 and 2008, respectively, on financial derivatives related to our midstream activities.

Operating Expenses.  Midstream operating expenses decreased between the periods primarily due to a $11.4 million goodwill impairment charge related to our Canyon assets in 2008. Additionally, we experienced a decrease in compressor expense of $1.9 million, a decrease in plant operating expenses of $1.6 million and a net decrease in other operating expenses of $1.8 million. These decreases were offset by an increase in ad valorem taxes of $2.9 million due to increased property values.

Depreciation and Amortization.  Midstream depreciation and amortization expense increased between the periods primarily due to incremental depreciation from the continued expansion of our Godley plant.

Selling, General and Administrative Expenses.  Midstream selling, general and administrative expenses decreased between the periods primarily due to a decrease in employee-related costs (including allocated overhead expenses) of approximately $16.8 million. This decrease was partially offset by an increase in professional fees of $3.0 million, $10 million related to the FERC settlement and a net increase of $0.9 million in other general and administrative expenses.

 

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Retail Propane and Other Retail Propane Related

 

     Years Ended December 31,    Change  
     2009    2008   

Retail propane gallons sold (in thousands)

     568,315      601,134      (32,819

Retail propane revenues

      $     1,190,523       $     1,514,599       $ (324,076

Other retail propane related revenues

     102,060      109,411      (7,351

Retail propane cost of products sold

     574,854      1,014,068          (439,214

Other retail propane related cost of products sold

     21,148      24,654      (3,506
                      

Gross margin

     696,581      585,288      111,293   

Operating expenses

     341,935      350,280      (8,345

Depreciation and amortization

     83,476      79,717      3,759   

Selling, general and administrative

     41,941      40,727      1,214   
                      

Segment operating income

      $ 229,229       $ 114,564       $ 114,665   
                      

Volumes.  Retail propane volumes decreased primarily due to the continued effects of customer conservation, the impact of the economic recession, and to a lesser extent, the decline in new home construction. These decreases were partially offset by volume increases from acquisitions that were made after January 1, 2008 and therefore were not included in the results for the full year ended December 31, 2008. We use information on temperatures based on heating degree days published by the National Oceanic and Atmospheric Administration (“NOAA”) to analyze how our volume sales are affected by temperature. Our normal temperatures are based on the average heating degree days provided by NOAA for various data points in our operating areas for the 10-year period ending December 2009. Based on this information, we calculate a ratio of actual heating degree days to normal heating degree days. Temperatures during the year ended December 31, 2009 were 4.1% colder than normal and were just slightly colder than the year ended December 31, 2008.

Gross Margin.  Total gross margin increased $111.3 million or 19.0% for the year ended December 31, 2009 compared to the year ended December 31, 2008. This increase was principally due to the benefit of the rapid decline in commodity prices in the first half of 2009 compared to the historically high commodity prices reached in 2008, which resulted in a reduction in product costs that outpaced the decline in average selling prices and the impact of mark-to-market accounting of our financial instruments. The average sales price per retail gallon sold decreased approximately 17.0% for the year ended December 31, 2009 compared to the year ended December 31, 2008 while the average cost per gallon of propane was approximately 35.0% lower during the year ended December 31, 2009 as compared to the year ended December 31, 2008. To hedge a significant portion of our propane sales commitments entered into under our customer prebuy programs, we utilize financial instruments to lock in margins. Prior to April 2009, these financial instruments were not designated as cash flow hedges for accounting purposes, and changes in market value were recorded in cost of products sold in the consolidated statements of operations. During 2009, our propane margins were positively impacted by the settlement of financial instruments related to sales commitments that were entered into in 2008. We recognized unrealized losses of $45.6 million on these financial instruments during 2008 and we recognized unrealized gains of $45.6 million when they settled in 2009.

Operating Expenses.  The decrease in operating expenses was principally due to a decrease of $9.7 million in vehicle fuel used for delivery to customers due to the significant decline in fuel prices between the periods, a decrease of $4.0 million in bad debt expense due to improved collections in the accounts receivable in 2009, which also lead to a reduction in our reserve for bad debts, and a decrease of $2.9 million related to cost control initiatives from our operations. These decreases were offset by an increase in payroll costs of $3.9 million due to an increase related to additional employees from acquisitions in the latter part of 2008, merit increases, and an increase in medical expenses of $4.2 million. Our business insurance reserves and claims also increased by $5.2 million.

 

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Depreciation and Amortization Expense.  The increase in depreciation and amortization expense was primarily related to assets added through acquisitions in the latter part of 2008.

Selling, General and Administrative.  The increase in selling, general and administrative expenses between comparable periods was primarily due to increased administrative expense allocations of $1.5 million offset by a reduction in other non-recurring expenses incurred during the prior periods.

Year Ended December 31, 2008 Compared to the Year Ended August 31, 2007 (tabular dollar amounts are expressed in thousands)

Parent Company Only Results

The following table summarizes the key components of the stand-alone results of operations of the Parent Company for the periods indicated:

 

     Years Ended     Change  
     December 31,  
2008
      August 31,  
2007
   

Equity in earnings of affiliates

      $ 551,835         $ 435,247         $ 116,588   

Selling, general and administrative expenses

     6,453        8,496        (2,043

Interest expense

     91,822            104,405            (12,583

Losses on non-hedged interest rate derivatives

         (77,435     (1,952     (75,483

Other, net

     (1,056     (405     (651

The following is a discussion of the highlights of the Parent Company’s stand-alone results of operations for the periods presented.

Equity in Earnings of Affiliates.  Equity in earnings of affiliates represents earnings of the Parent Company related to its investment in limited partner units of ETP, its ownership of ETP GP and its ownership of ETP LLC. The increase in equity in earnings of affiliates was directly related to the changes in the ETP segment income described below.

Interest Expense.  The Parent Company interest expense decreased primarily due to a decrease in the LIBOR rate between the periods.

Gains (Losses) on Non Hedged Interest Rate Derivatives.  The Parent Company has interest swaps with a notional amount of $800.0 million that are not accounted for as hedges. Changes in the fair value of these swaps are recorded directly in earnings. The variable portion of these swaps are based on the three month LIBOR and its corresponding forward curve. A decrease in these rates between the comparable periods resulted in decreases in the swaps’ fair value and settlement amounts during the year ended December 31, 2008 compared with the year ended August 31, 2007.

 

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Consolidated Results

 

     Years Ended     Change  
   December 31,
2008
    August 31,
2007
   

Revenues

      $     9,293,367         $     6,792,037         $     2,501,330   

Cost of products sold

     6,938,080        5,078,206        1,859,874   
                        

Gross margin

     2,355,287        1,713,831        641,456   

Operating expenses

     781,831        559,600        222,231   

Depreciation and amortization

     274,372        191,383        82,989   

Selling, general and administrative

     200,181        153,512        46,669   
                        

Operating income

     1,098,903        809,336        289,567   

Interest expense, net of interest capitalized

     (357,541     (279,986     (77,555

Equity in earnings (losses) of affiliates

     (165     5,161        (5,326

Losses on disposal of assets

     (1,303     (6,310     5,007   

Gains (losses) on non-hedged interest rate derivatives

     (128,423     29,081        (157,504

Allowance for equity funds used during construction

     63,976        4,948        59,028   

Other, net

     8,115        1,129        6,986   

Income tax expense

     (3,808     (11,391     7,583   
                        

Net income

      $ 679,754         $ 551,968         $ 127,786   
                        

See the detailed discussion of revenues, costs of products sold, gross margin, operating expenses, and depreciation and amortization by operating segment below.

Interest Expense.  Interest expense increased principally due to higher levels of borrowings, which were used to finance growth capital expenditures in our intrastate transportation and storage and interstate transportation operations.

Equity in Earnings (Losses) of Affiliates.  The decrease in equity in earnings (losses) of affiliates is primarily due to the recognition of $5.1 million of equity income from our 50% ownership of CCEH during September 1, 2006 through December 1, 2006. We redeemed our investment in CCEH in connection with our Transwestern acquisition on December 1, 2006; therefore, no amounts are reflected in equity in earnings (losses) of affiliates with respect to CCEH after that date.

Gain (Loss) on Non-Hedged Interest Rate Derivatives.  The Partnership had interest rate swaps at December 31, 2008 and August 31, 2007, with notional amounts of $1.43 billion and $0.93 billion, respectively, that were not designated as hedges. Changes in the value of these swaps were recorded directly in earnings. The variable portion of these swaps was based on the three month LIBOR and its corresponding forward curve. A decrease in these rates during the comparable period resulted in decreases in the swaps’ fair value and settlement amounts during the year ended December 21, 2008 compared with the year ended August 31, 2007. In addition, the Partnership recorded a gain of $31.5 million on the settlement of a forward starting swap during the period ended August 31, 2007.

Allowance for Equity Funds Used During Construction.  The increase between comparable twelve month periods is due to construction within our interstate transportation segment, which is primarily related to the Phoenix Expansion project that was subsequently completed in February 2009.

Other, Net.  The increase between the comparable twelve month periods is principally due to $7.1 million from the excess of contributions in aid of construction costs related to $40.0 million reimbursement in connection with an extension on our Southeast Bossier pipeline.

 

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Income Tax Expense.  As a partnership, we are generally not subject to income taxes. However, certain wholly-owned subsidiaries are corporations that are subject to income taxes.

The decrease in income tax expense was primarily due to a $12.0 million tax benefit associated with a trading loss incurred by one of our corporate subsidiaries in July 2008. This tax benefit was offset by higher taxes resulting from increased earnings during the year. For additional information related to income tax expense, see Note 9 to our consolidated financial statements.

Segment Operating Results

Operating income by segment is as follows:

 

     Years Ended     Change  
   December 31,
2008
    August 31,
2007
   

Intrastate transportation and storage

     $ 710,070        $     479,820        $     230,250   

Interstate transportation

     124,676        95,650        29,026   

Midstream

     162,471        119,233        43,238   

Retail propane and other retail propane related

     114,564        124,263        (9,699

All other

     (2,032     1,735        (3,767

Unallocated selling, general and
administrative expenses

     (10,846     (11,365     519   
                        

Operating income

     $     1,098,903        $ 809,336        $ 289,567   
                        

Unallocated Selling, General and Administrative Expenses.  Prior to December 2006, the selling, general and administrative expenses that relate to the general operations of the Partnership were not allocated to our segments. In conjunction with the Transwestern acquisition in December 2006, selling, general and administrative expenses are now allocated monthly to the Operating Companies using the MMFC. The expenses subject to allocation are based on estimated amounts and take into consideration actual expenses from previous months and known trends. The difference between the allocation and actual costs is adjusted in the following month.

Intrastate Transportation and Storage

 

     Years Ended    Change  
   December 31,
2008
   August 31,
2007
  

Natural gas MMBtu/d - transported

         11,187,327      6,124,423      5,062,904   

Natural gas MMBtu/d - sold

     1,389,781      1,400,753      (10,972

Revenues

      $ 5,634,604       $ 3,915,932       $ 1,718,672   

Cost of products sold

     4,467,552          3,137,712          1,329,840   
                      

Gross margin

     1,167,052      778,220      388,832   

Operating expenses

     287,515      181,133      106,382   

Depreciation and amortization

     92,979      64,423      28,556   

Selling, general and administrative

     76,488      52,844      23,644   
                      

Segment operating income

      $ 710,070       $ 479,820       $ 230,250   
                      

 

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Gross Margin.  The increase in intrastate transportation and storage gross margin between periods was comprised of the following factors:

 

  Ÿ  

Overall volumes on our transportation pipelines were higher due to increased demand to transport natural gas out of the Barnett Shale and Bossier Sands producing regions, increased demand for natural gas used by electricity-producing power plants connected to our assets and the completion of several pipeline expansion projects. The increase in transport volumes were also due to favorable market conditions between the Waha and Katy/Houston Ship Channel market hubs resulting in higher volumes and higher average rates on our intrastate pipeline systems. Transportation fees increased approximately $281.3 million for the year ended December 31, 2008 as compared to the year ended August 31, 2007. Fuel retention revenue increased approximately $130.3 million due to increased volumes transported through our transportation pipelines;

 

  Ÿ  

Higher natural gas prices resulting in additional retention margin of $35.8 million. Our average natural gas prices for retained fuel increased to an average of $9.66/MMBtu during the year ended December 31, 2008 from an average of $6.69/MMBtu during the year ended August 31, 2007; and,

 

  Ÿ  

A decrease in natural gas storage-related margin of $51.3 million. Realized margin, comprised of both margin on the withdrawal and sale of natural gas and realized gains on derivative instruments related to our storage operations, decreased by $79.2 million for the year ended December 31, 2008 compared to the year ended August 31, 2007. During the year ended December 31, 2008, there were physical sales of 39.5 Bcf of natural gas from our Bammel storage facility compared to 67.6 Bcf in the 2007 period. In addition, between the comparable twelve month periods, there was an increase of $13.1 million in storage fees, primarily due to a new contract that commenced on April 1, 2007 at our Bammel storage facility. Furthermore, we recognized unrealized mark-to-market gains related to our storage operations (which represent the change in the fair value of derivative instruments not designated as hedges for accounting purposes) of $89.9 million during the year ended December 31, 2008 compared to $5.6 million during the year ended August 31, 2007. The amount that we will ultimately realize, however, is subject to change as commodity prices change in future months and the underlying physical transaction occurs. In addition, we recognized a net lower-of-cost-or-market adjustment of $47.8 million related to natural gas stored in our Bammel facility during the year ended December 31, 2008.

Operating Expenses.  Intrastate transportation and storage operating expenses increased between periods primarily due to increased fuel consumption of $90.4 million, increased utility expenses of $10.5 million, increased compressor maintenance expenses of $7.5 million, increased pipeline maintenance expenses of $7.5 million and increased employee costs of $7.5 million. These increases were offset by decreases of $11.4 million in compressor rental expense as well as a $5.6 million decrease in measurement fees.

Selling, General and Administrative Expenses.  Intrastate transportation and storage selling, general and administrative expenses increased between periods primarily due to an increase of $15.7 million in allocated legal fees and an increase in other allocated costs of $8.3 million.

Depreciation and Amortization.  Intrastate transportation and storage depreciation and amortization expense increased between periods primarily due to the continuing expansion of our pipeline system, most notably the Southeast Bossier and Maypearl to Malone pipelines.

 

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Interstate Transportation

 

     Years Ended    Change
   December 31,
2008
   August 31,
2007
  

Natural gas MMBtu/d - transported

         1,777,097          1,802,109          (25,012)

Natural gas MMBtu/d - sold

     15,162      19,680      (4,518)

Revenues

      $ 244,224       $ 178,663       $ 65,561

Operating expenses

     56,906      36,295      20,611

Depreciation and amortization

     37,790      27,972      9,818

Selling, general and administrative

     24,852      18,746      6,106
                    

Segment operating income

      $ 124,676       $ 95,650       $ 29,026
                    

For all categories above, the increase between the year ended December 31, 2008 and the year ended August 31, 2007 is primarily due to the results for the year ended August 31, 2007 only including nine months of activity from the date of the Transwestern acquisition (December 1, 2006). The results for the year ended December 31, 2008 include the entire twelve months.

Midstream

 

     Years Ended    Change
   December 31,
2008
   August 31,
2007
  

Natural gas MMBtu/d - sold

     1,269,724      941,140      328,584

NGLs Bbls/d - sold

     25,939      17,907      8,032

Revenues

      $ 5,342,393       $ 2,853,496       $ 2,488,897

Cost of products sold

         4,986,495          2,632,187          2,354,308
                    

Gross margin

     355,898      221,309      134,589

Operating expenses

     82,872      39,148      43,724

Depreciation and amortization

     63,287      27,331      35,956

Selling, general and administrative

     47,268      35,597      11,671
                    

Segment operating income

      $ 162,471       $ 119,233       $ 43,238
                    

Gross Margin.  Midstream gross margin increased between periods primarily due to the following factors:

 

Ÿ  

An increase in fee-based revenue and processing margin of $82.9 million and $55.6 million, respectively, from our gathering and processing assets (other than our Canyon Gathering System). The increase was due to incremental volumes from the expansion of the Godley plant since placing it into service as well as favorable market conditions to process and extract NGLs;

 

Ÿ  

Incremental margin of $25.1 million due to the acquisition of the Canyon Gathering System in October 2007; and,

 

Ÿ  

A net decrease of $24.7 million in margin from our trading and marketing activities. Net realized and unrealized trading losses were $26.2 million for the year ended December 31, 2008, compared to a net gain of $2.2 million for the year ended August 31, 2007. The loss for the year ended December 31, 2008 was due to unfavorable market conditions. Other marketing activities resulted in a margin of $23.3 million for the year ended December 31, 2008 compared to $19.6 million for the year ended August 31, 2007.

 

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Operating Expenses.  Midstream operating expenses increased primarily due to increased employee-related costs of $10.2 million, increased plant operating expenses of $5.1 million, increased ad valorem tax of $3.2 million, increased compressor rental expense of $3.1 million, increased chemicals expense of $3.1 million, increased vehicles expense of $1.8 million, and increases in other expenses of $5.8 million. These increases were primarily due to the expansion of the Godley plant and the acquisition of the Canyon Gathering System in October 2007. In addition, operating expenses for the year ended December 31, 2008 includes an $11.4 goodwill impairment loss associated with the Canyon Gathering System.

Selling, General and Administrative Expenses.  Midstream selling, general and administrative expenses increased primarily due to increased employee-related costs of $16.7 million, an increase of $4.2 million in measurement and technology-related expenses, offset by a $7.3 million decrease in allocated legal fees and a decrease of $8.3 million in allocated administrative overhead expenses. Other expenses increased by a net $6.4 million.

Depreciation and Amortization.  Midstream depreciation and amortization expense increased between periods primarily due to incremental depreciation related to the Canyon Gathering System acquisition in October 2007 and the continued expansion of the Godley plant.

Retail Propane and Other Retail Propane Related

 

     Years Ended    Change  
   December 31,
2008
   August 31,
2007
  

Retail propane gallons sold (in thousands)

     601,134      604,269      (3,135

Retail propane revenues

      $     1,514,599       $     1,179,073       $     335,526   

Other retail propane related revenues

     109,411      105,794      3,617   

Retail propane cost of products sold

     1,014,068      734,204      279,864   

Other retail propane related cost of products sold

     24,654      25,430      (776
                      

Gross margin

     585,288      525,233      60,055   

Operating expenses

     350,280      297,469      52,811   

Depreciation and amortization

     79,717      70,833      8,884   

Selling, general and administrative

     40,727      32,668      8,059   
                      

Segment operating income

      $ 114,564       $ 124,263       $ (9,699
                      

Volumes. The slight decrease in gallons sold for the year ended December 31, 2008 compared to the year ended August 31, 2007 was primarily due to the continued conservation from customers over the past twelve months, offset by the volumes added through acquisitions after August 31, 2007. For the year ended December 31, 2008 the weather was 5.3% colder than the year ended August 31, 2007, but volume trends did not track as closely to weather pattern trends in 2008 due to the slow down in new home construction, the economic recession and increased fuel prices that caused the aforementioned customer conservation.

Gross Margin. The increase in gross margins was principally due to our ability to manage retail selling prices despite the decrease in wholesale propane prices, particularly in the latter part of 2008. Retail fuel gross margins were $0.0966 per gallon higher for the year ended December 31, 2008 as compared to the year ended August 31, 2007. The average sales price per retail gallon sold increased approximately 29.1% for the year ended December 31, 2008 compared to the year ended August 31, 2007. Fuel prices significantly declined during the last three months of the year ended December 31, 2008, but the overall price per gallon for the year ended December 31, 2008 was 38.8% higher than the year ended August 31, 2007. In addition, we entered into propane sales commitments with a portion of our retail customers that provide for a contracted price agreement for a specified period of time, typically no longer than one year. These commitments can expose the operations to product price risk if not offset by a propane purchase commitment. To hedge a significant portion of these sales

 

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commitments, we utilize financial instruments to lock in margins. These financial instruments were not designated as hedges for accounting purposes, and the change in market value was recorded in cost of products sold in the consolidated statements of operations. The cost of products sold for the propane operations was negatively impacted by the decline in propane prices from the time the agreements were entered into. Unrealized losses of $45.6 million were recorded through cost of products sold during the year ended December 31, 2008, on these financial instruments. There were minimal losses during the year ended August 31, 2007.

Operating Expenses. Operating expenses increased between the comparable periods due to various factors. Although volumes were relatively flat, vehicle fuel and lube used for delivery to customers increased $10.7 million primarily due to the increase in the average fuel costs between the comparable periods. Wages, deferred compensation and other employee benefits increased $24.5 million due to an increase in headcount as a result of acquisitions and cost of living increases were given to existing employees. The employee-related increases were offset by savings from delays in hiring seasonal employees due to volume pressures described above. Bad debt expense has increased a net $4.2 million as the general economy has also shown pressure on the collection of receivables leading to a decision to increase accounts receivable reserves. Our operational employee incentive program was $7.2 million higher for the year ended December 31, 2008 as compared to August 31, 2007, due to more favorable results achieved during the year ended December 31, 2008 than during the year ended August 31, 2007.

Selling, General and Administrative Expenses. The increase in selling, general and administrative expenses between the comparable periods was primarily due to increased administrative expense allocations of $2.4 million, increases in wages, deferred compensation and other employee related benefits of $2.7 million, and consulting and other costs related to information technology systems implementations and non-recurring costs related to property settlements in 2008.

Depreciation and Amortization Expense. The increase in depreciation and amortization expense between the comparable periods was primarily due to the incremental expense resulting from acquisitions made subsequent to August 31, 2007.

Four Months Ended December 31, 2007 compared to the Four Months Ended December 31, 2006 (unaudited tabular dollar amounts in thousands)

In November 2007, we changed our fiscal year end from August 31 to December 31 and, in connection with such change, we are including comparative financial results for the four-month transition period of September 1, 2007 to December 31, 2007.

Parent Company Only Results

The following table summarizes the key components of the stand-alone results of operations of the Parent Company for the periods indicated:

 

     Four Months Ended
December 31,
    Change  
   2007     2006    

Equity in earnings of affiliates

      $     168,547        $     107,586         $     60,961   

Selling, general and administrative expenses

     (2,875     (3,131     256   

Interest expense

     (37,071     (28,026     (9,045

Losses on non-hedged interest rate derivatives

     (27,670     -        (27,670

Other, net

     (8,128     252        (8,380

 

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The following is a discussion of the highlights of the Parent Company’s stand-alone results of operations for the periods presented.

Equity in Earnings of Affiliates. Equity in earnings of affiliates represents earnings of the Parent Company related to its investment in limited partner units of ETP, its ownership of ETP GP and its ownership of ETP LLC. The increase in equity in earnings of affiliates was directly related to the changes in the ETP segment income described below.

Interest Expense. The Parent Company interest expense increased because the Parent Company entered into a $1.30 billion Senior Secured Term Loan Facility on November 1, 2006. Such borrowings were outstanding for the entire four months ended December 31, 2007.

Losses on Non-Hedged Interest Rate Derivatives. See discussion below in Other, net.

Other, Net. The change in other, net was due primarily to losses of $27.7 million on changes in value of interest rate swaps that are not accounted for as hedges. Such gains and losses were included in interest expense during the four months ended December 31, 2006. The four months ended December 31, 2007 also included an expense of $7.8 million for liquidated damages under the registration rights agreements for the March 2007 and November 2006 private placement of ETE Common Units (as described in Note 7 to our consolidated financial statements).

Consolidated Results

 

     Four Months Ended
December 31,
    Change  
   2007     2006    

Revenues

      $     2,349,342         $     2,162,466         $     186,876   

Cost of products sold

     1,673,654        1,689,843        (16,189
                        

Gross margin

     675,688        472,623        203,065   

Operating expenses

     221,757        173,365        48,392   

Depreciation and amortization

     75,406        52,840        22,566   

Selling, general and administrative

     61,874        43,602        18,272   
                        

Operating income

     316,651        202,816        113,835   

Interest expense, net of interest capitalized

     (103,375     (82,979     (20,396

Equity in earnings (losses) of affiliates

     (94     4,743        (4,837

Gains on disposal of assets

     14,310        2,212        12,098   

Other, net

     (34,734     2,248        (36,982

Income tax expense

     (9,949     (2,155     (7,794
                        

Net income

      $ 182,809         $ 126,885         $ 55,924   
                        

See the detailed discussion of revenues, cost of products sold, margin, operating expenses, and depreciation and amortization by operating segment below.

Interest Expense. Interest expense increased $20.4 million principally due to a net $9.0 million increase in interest expense related to borrowings of the Parent Company, a net $13.8 million increase in interest expense related to increased borrowings on ETP’s Senior Notes and the ETP Credit Facility and $0.5 million of interest on borrowings related to the Transwestern acquisition. Partnership borrowings increased primarily due to the financing of our growth capital expenditures and the Canyon acquisition. The increased interest expense was offset by $2.0 million of unrealized losses related to non-hedged interest rate swaps included in interest expense for the four months ended December 31, 2006. Unrealized gains and losses related to non-hedged interest rate

 

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swaps were included in other income (expense), net for the four months ended December 31, 2007. The increase in interest expense was also offset by propane related interest, which decreased $2.0 million due primarily to the scheduled debt payments that have occurred between the four-month periods.

Equity in Earnings of Affiliates. The decrease in equity in earnings (losses) of affiliates was due primarily to $5.1 million of equity income from our 50% ownership of the member interests in CCE Holdings, LLC (“CCEH”) for the month of November 2006. We redeemed our investment in CCEH in connection with our Transwestern acquisition on December 1, 2006. We do not include earnings from equity method unconsolidated affiliates in our measurement of operating income because such earnings have not been significant historically.

Gain on Sale of Assets. On October 1, 2007, we sold our 60% interest in a Canadian wholesale fuel business for a gain of $10.2 million.

Income Tax Expense. As a partnership, we are generally not subject to income taxes. However, certain wholly-owned subsidiaries are corporations that are subject to income taxes.

The increase in income tax expense was primarily related to $3.9 million recorded for the four months ended December 31, 2007 of Texas margin tax that was not effective until January 1, 2007 and $3.9 million of taxes on the gain on the sale of our interest in a Canadian wholesale fuel business.

Losses on Non-Hedged Interest Rate Derivatives. See discussion below in Other, Net.

Other, Net. The change in other, net, was due to the factors discussed above for the Parent Company results.

Segment Operating Results

Operating income by segment is as follows:

 

     Four Months Ended
December 31,
    Change  
   2007     2006    

Intrastate transportation and storage

      $     169,361         $     109,262         $     60,099   

Interstate transportation

     29,657        11,854        17,803   

Midstream

     71,853        40,421        31,432   

Retail propane and other retail propane related

     46,747        49,841        (3,094

All other

     (796     528        (1,324

Unallocated selling, general and administrative expenses

     (171     (9,090     8,919   
                        

Operating income

      $ 316,651         $ 202,816         $ 113,835   
                        

Unallocated Selling, General and Administrative Expenses. Prior to December 2006, the selling, general and administrative expenses that relate to the general operations of the Partnership were not allocated to our segments. In conjunction with the Transwestern acquisition, selling, general and administrative expenses are now allocated monthly to the Operating Companies using the MMFC. The expenses subject to allocation are based on estimated amounts and take into consideration actual expenses from previous months and known trends. The difference between the estimated allocation and actual costs is adjusted in the following month. For the four months ended December 31, 2007, a net $12.1 million allocation to the Operating Companies exceeded total incurred costs.

 

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Intrastate Transportation and Storage

 

    Four Months Ended
December 31,
  Change  
  2007   2006  

Natural gas MMBtu/d - transported

    8,787,387     4,889,029         3,898,358   

Natural gas MMBtu/d - sold

    1,259,566     1,379,721     (120,155

Revenues

     $     1,254,401      $     1,195,871      $ 58,530   

Cost of products sold

    964,568     994,511     (29,943
                   

Gross margin

    289,833     201,360     88,473   

Operating expenses

    76,428     56,452     19,976   

Depreciation and amortization

    23,429     19,020     4,409   

Selling, general and administrative

    20,615     16,626     3,989   
                   

Segment operating income

     $ 169,361      $ 109,262      $ 60,099   
                   

Volumes and Gross Margin. Increases in intrastate transportation and storage volumes and gross margin are comprised of the following factors:

 

Ÿ  

Transported natural gas volumes increased principally due to the increased volumes experienced on the ET Fuel and East Texas Pipeline systems as a result of the completion of the Cleburne to Carthage Pipeline, increased demand to transport natural gas out of the Barnett Shale and Bossier Sands producing regions, and the continued effort to secure long-term shipper contracts.

 

Ÿ  

Natural gas sales volumes on the HPL System decreased primarily due to the new CenterPoint contract that commenced on April 1, 2007. Under the previous contract, we sold and delivered natural gas to CenterPoint for a bundled price. Under the terms of the new agreement, CenterPoint has contracted for 129 Bcf per year of firm transportation capacity combined with 10 Bcf of working gas capacity in our Bammel storage facility.

 

Ÿ  

Transportation fees increased approximately $53.2 million. Retention revenue increased approximately $29.7 million due to increased volumes transported through our transportation pipelines;

 

Ÿ  

Increase in processing margin of $8.6 million from our HPL system. Processing margins generated from our HPL system benefited from favorable market conditions to process and extract NGLs during the four months ended December 31, 2007; and

 

Ÿ  

Net decrease in storage margins of $9.4 million. During the four months ended December 31, 2006, we recognized approximately $27.0 million of margin on 13 Bcf of gas sold from our Bammel facility. Due to market conditions, there were no withdrawals in the same period in 2007; however, we did recognize $9.2 million in gains from the discontinuation of hedge accounting resulting from our determination that originally forecasted sales of natural gas from the Partnership’s Bammel storage facility were no longer probable to occur by the specified time period, or within an additional two-month time period thereafter. In addition, fee-based storage revenues increased $8.4 million primarily due to the new Centerpoint contract, which commenced on April 1, 2007 in which Centerpoint contracted for 10 Bcf of working gas capacity in our Bammel storage facility.

Operating Expenses. Intrastate transportation and storage operating expenses increased $20.0 million primarily due to an increase of $11.4 million in fuel consumption, an increase of $4.5 million in electricity costs, an increase of $6.1 million in compressor and pipeline maintenance and an increase of $2.0 million in employee related costs such as salaries, incentive compensation and healthcare costs. These increases were offset by a $2.8 million decrease in compressor rentals and a $2.9 million decrease in professional fees related to the EMS contract buyout in September 2007.

Selling, General and Administrative Expenses. Intrastate transportation and storage selling, general and administrative expenses increased $4.0 million principally due to an increase in general and administrative expenses allocated from the midstream segment as noted above.

 

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Depreciation and Amortization. Intrastate transportation and storage depreciation and amortization expense increased $4.4 million principally due to additions to property and equipment most notably the Cleburne to Carthage Pipeline.

Interstate Transportation

 

    Four Months Ended
December 31,
  Change  
  2007   2006  

Natural gas MMBtu/d - transported

        1,708,477         1,822,065         (113,588

Natural gas MMBtu/d - sold

    13,663     14,104     (441

Revenues

     $ 76,000      $ 19,003      $ 56,997   

Operating expenses

    23,922     1,396     22,526   

Depreciation and amortization

    12,305     3,191     9,114   

Selling, general and administrative

    10,116     2,562     7,554   
                   

Segment operating income

     $ 29,657      $ 11,854      $ 17,803   
                   

The increase in all categories was attributable to the Transwestern acquisition on December 1, 2006.

Midstream

 

     Four Months Ended
December 31,
   Change
   2007    2006   

Natural gas MMBtu/d - sold

         1,090,090          968,016          122,074

NGLs Bbls/d - sold

     25,389      12,458      12,931

Revenues

      $ 1,166,313       $ 905,392       $ 260,921

Cost of products sold

     1,043,191      839,561      203,630
                    

Gross margin

     123,122      65,831      57,291

Operating expenses

     17,633      11,710      5,923

Depreciation and amortization

     14,943      7,748      7,195

Selling, general and administrative

     18,693      5,952      12,741
                    

Segment operating income

      $ 71,853    $ 40,421       $ 31,432
                    

Gross Margin.  Midstream’s gross margin increased between comparable periods primarily due to the following factors:

 

Ÿ  

Increases in processing margin of $37.6 million and fee-based revenue of $17.9 million from our gathering and processing assets. The increase was due to incremental volumes from the completion of our Godley plant in October 2006, the continued expansion of the plant since placing it into service, and the acquisition of three gathering systems during the first six months of the 2007 fiscal year. In addition, our midstream assets benefited from favorable market conditions to process and extract NGLs during the four months ended December 31, 2007. Due to changes in the contract structures at our Godley plant, arrangements for which we had been recognizing the increased margin from favorable conditions converted to long-term fee-based contracts in November 2007. As such, we expect margin from processing at our Godley plant to be more predictable and less sensitive to commodity price volatility. As of December 31, 2007, the Godley plant had approximately 500 MMcf/d of cryoprocessing capacity and 100 MMcf/d of dew point processing capacity;

 

Ÿ  

Increase in non-trading margin from our marketing activities of $1.0 million as market conditions resulted in higher sales volumes conducted by our producer services’ operations;

 

Ÿ  

Decrease in net trading revenues of $5.2 million; and,

 

Ÿ  

Canyon Gathering System – The acquisition of the Canyon Gathering System on October 5, 2007 contributed approximately $5.6 million of incremental margin for the four months ended December 31, 2007.

 

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Operating Expenses.  Midstream operating expenses increased $5.9 million, primarily driven by increased employee-related costs such as salaries, incentive compensation and healthcare costs of $2.2 million, increased compressor rentals of $1.5 million, and increased pipeline and compressor maintenance expense of $0.7 million. The increases were principally due to the gathering system acquisitions in fiscal 2007, the start up and continued expansion of the Godley plant, and the Canyon acquisition.

Selling, General and Administrative Expenses.  Midstream selling, general and administrative expenses increased $12.7 million, which was attributable to $9.2 million in increased legal fees principally related to regulatory matters, a $4.2 million allocation of parent company administrative expenses for overhead costs that previously had not been allocated in 2006, and a $1.9 million increase in employee-related costs such as salaries, incentive compensation and healthcare costs. These factors were offset by a $5.8 million increase of general and administrative expenses allocated to the transportation segment. The allocation of general and administrative expenses between the midstream and the intrastate transportation and storage segments is based on the MMFC and is intended to fairly present the segment’s operating results.

Depreciation and Amortization.  Midstream depreciation and amortization expense increased $7.2 million principally due to additions to property and equipment including the completion and continued expansion of our Godley plant, and the acquisition of certain gathering systems in 2006.

Retail Propane and Other Retail Propane Related

 

     Four Months Ended
December 31,
   Change  
   2007    2006   

Retail propane gallons sold (in thousands)

     205,311      214,623      (9,312

Retail propane revenues

      $     471,494       $     409,821       $     61,673   

Other retail propane related revenues

     39,764      40,020      (256

Retail propane cost of products sold

     315,698      256,994      58,704   

Other retail propane related cost of products sold

     9,460      10,344      (884
                      

Gross margin

     186,100      182,503      3,597   

Operating expenses

     102,537      101,508      1,029   

Depreciation and amortization

     24,537      22,520      2,017   

Selling, general and administrative

     12,279      8,634      3,645   
                      

Segment operating income

      $ 46,747       $ 49,841       $ (3,094
                      

Volumes.  Total gallons sold by our retail propane operations decreased due to a combination of below normal degree days, customer conservation and the slow down of new home construction in our propane markets. The overall weather in our areas of operations during the four months ended December 31, 2007 was 2.9% warmer than the four months ended December 31, 2006 and 9.8% warmer than normal.

Gross Margin.  Overall gross margins increased $3.6 million even though gallon sales decreased. Retail propane revenues increased mainly due to increased sale prices driven by increased cost of fuel. This increase was offset by 9.8% warmer than normal weather and 2.9% warmer weather than the same period last year. Retail propane cost of products sold increased mainly related to the increase in overall cost of fuel to the company offset by the decrease in gallons sold. On an average, fuel costs were approximately $0.35/gallon higher. Optimization of the margins is influenced by market opportunities, independent competitors and concerns for long term retention of customers.

Operating Expenses.  Operating expenses increased by $1.0 million. Included in these operating expenses were increases related to higher vehicle fuel costs and other vehicle expenses, offset by the cost conservation efforts of the retail operations and the delay in hiring seasonal staff due to the warmer weather.

 

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Selling, General and Administrative Expenses.  The increase in selling, general and administrative expenses was primarily due to increased administrative expense allocations. Effective with the Transwestern acquisition in December 2006, an allocation of general and administrative expenses based on the MMFC is now made to the operating companies, which increased the retail propane selling, general and administrative expenses by a net $5.1 million for the four months ended December 31, 2007. This increase from the allocation of expenses was offset by the reduction of certain personnel costs at the propane operating partnerships.

Depreciation and Amortization Expense.  The increase in depreciation and amortization expense was primarily due to the depreciation and amortization of assets and amortizable intangibles added through acquisitions made after December 31, 2006.

Liquidity and Capital Resources

Parent Company Only

The Parent Company currently has no separate operating activities apart from those conducted by ETP and its Operating Companies. The principal sources of cash flow for the Parent Company are its direct and indirect investments in the limited and general partner interests of ETP. The amount of cash that ETP can distribute to its partners, including the Parent Company, each quarter is based on earnings from ETP’s business activities and the amount of available cash, as discussed below. The Parent Company also has a $500.0 million revolving credit facility that expires in February 2011 with available capacity of $376.0 million as of December 31, 2009.

The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its general and limited partners. The Parent Company currently expects to fund its short-term needs for such items with its distributions from ETP.

ETP

ETP’s ability to satisfy its obligations and pay distributions to its Unitholders will depend on its future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management’s control.

ETP currently believes that its business has the following future capital requirements:

 

Ÿ  

growth capital expenditures for our midstream and intrastate transportation and storage segments primarily for construction of new pipelines and compression, for which we expect to spend between $200 million and $230 million in 2010;

 

Ÿ  

growth capital expenditures for our interstate transportation segment, excluding capital contributions to our joint ventures as discussed below, for the construction of new pipelines for which we expect to spend between $1.01 billion and $1.06 billion in 2010;

 

Ÿ  

growth capital expenditures for our retail propane segments of between $30 million and $40 million in 2010; and

 

Ÿ  

maintenance capital expenditures of between $110 million and $120 million during 2010, which include (i) capital expenditures for our intrastate operations for pipeline integrity and for connecting additional wells to our intrastate natural gas systems in order to maintain or increase throughput on existing assets; (ii) capital expenditures for our interstate operations, primarily for pipeline integrity; and (iii) capital expenditures for our propane operations to extend the useful lives of our existing propane assets in order to sustain our operations, including vehicle replacements on our propane vehicle fleet.

In addition to the capital expenditures noted above, we expect to make capital contributions to our joint ventures of between $90 million and $105 million in 2010. In November 2009, FEP entered into a $1.1 billion credit facility, which will be used to fund FEP’s capital expenditures. Therefore, we do not expect to make any capital contributions to FEP in 2010.

 

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In addition, we may enter into acquisitions, including the potential acquisition of new pipeline systems and propane operations.

ETP generally funds its capital requirements with cash flows from operating activities and, to the extent that they exceed cash flows from operating activities, with proceeds of borrowings under existing credit facilities, long-term debt, the issuance of additional Common Units or a combination thereof.

During the year ended December 31, 2009, ETP raised approximately $853.7 million in net proceeds from its January, April and October Common Unit offerings, $993.6 million in net proceeds from an offering of $1.0 billion aggregate principal amount of senior notes in April and $348.4 million in net proceeds from an offering of $350.0 million aggregate principal amount of senior notes at Transwestern in December 2009. In addition, ETP raised $81.5 million in net proceeds during November and December 2009 under an equity distribution program, as described in Note 7 to our consolidated financial statements. As of December 31, 2009, in addition to approximately $68.2 million of cash on hand, ETP had available capacity under the ETP Credit Facility of $1.79 billion. In addition, ETP received approximately $423.6 million of net proceeds from ETP’s Common Unit offering in January 2010. Based on current estimates, we expect to utilize these resources, along with cash from ETP’s operations, to fund our announced growth capital expenditures and working capital needs through the end of 2010. We or ETP may issue debt or equity securities prior to that time as we deem prudent to provide liquidity for new capital projects or other partnership purposes.

The assets used in ETP’s natural gas operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures. The assets utilized in ETP’s propane operations do not typically require lengthy manufacturing process time or complicated, high technology components. Accordingly, ETP does not have any significant financial commitments for maintenance capital expenditures in its businesses. From time to time ETP experiences increases in pipe costs due to a number of reasons, including but not limited to, replacing pipe caused by delays from mills, limited selection of mills capable of producing large diameter pipe timely, higher steel prices and other factors beyond its control. However, ETP includes these factors into its anticipated growth capital expenditures for each year.

Cash Flows

Our internally generated cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price for our products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions, and other factors.

For the discussion that follows, certain amounts in periods prior to 2009 have been reclassified to conform to the 2009 presentation, including changes to the presentation of noncontrolling interest resulting from the adoption of Accounting Standards Codification 810-10-65, which resulted in the reclassification of distributions to minority interests between cash flow from operating activities and cash flow from financing activities in our consolidated statement of cash flows.

Operating Activities

Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” above), excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation and amortization expense and non-cash executive compensation expense. The increase in depreciation and amortization expense during the periods presented primarily resulted from construction and acquisitions of assets, while changes in non-cash unit-based compensation expense result from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flow from operating activities also differ from earnings as a result of non-cash charges that may not be recurring, such as impairment charges and allowance for equity funds

 

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used during construction. The allowance for equity funds used during construction increases in periods when we have a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of price risk management assets and liabilities, timing of accounts receivable collection, payments on accounts payable, the timing of purchases and sales of propane and natural gas inventories, and the timing of advances and deposits received from customers.

Following is a summary of operating activities by period.

Year Ended December 31, 2009

Cash provided by operating activities during 2009, was $723.5 million and net income was $697.9 million. The difference between net income and cash provided by operations during 2009 consisted of non-cash charges of $377.5 million (principally depreciation and amortization expense of $325.0 million and non-cash compensation of $25.8 million, partially offset by the allowance for equity funds used during construction of $10.6 million), offset by net changes in operating assets and liabilities of $352.0 million.

Year Ended December 31, 2008

Cash provided by operating activities during 2008, was $1.14 billion. Net income was $679.8 million. The difference between net income and the net cash provided by operations for 2008 consisted of non-cash items totaling $332.4 million (principally depreciation and amortization expense of $274.4 million and non-cash compensation expense of $25.6 million) and changes in operating assets and liabilities of $131.6 million.

Four Months Ended December 31, 2007

Cash provided by operating activities during the four months ended December 31, 2007, was $208.6 million. The net cash provided by operations for the four months ended December 31, 2007 consisted of net income of $182.8 million, non-cash items totaling $75.1 million (principally depreciation and amortization expense), offset by changes in operating assets and liabilities of $49.3 million.

Year Ended August 31, 2007

Cash provided by operating activities during the year ended August 31, 2007, was $1.01 billion. The net cash provided by operations for the year ended August 31, 2007 consisted of net income of $552.0 million, non-cash items totaling $206.3 million (principally non-cash compensation expense of $10.5 million and depreciation and amortization expense of $191.4 million) and cash from changes in operating assets and liabilities of $248.1 million.

Investing Activities

Cash flows from investing activities primarily consist of cash amounts paid in acquisitions, capital expenditures, and cash contributions to our joint ventures. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects.

Following is a summary of investing activities by period.

Year Ended December 31, 2009

Cash used in investing activities during 2009 of $1.35 billion was comprised primarily of $530.3 million invested for growth capital expenditures (excluding the allowance for equity funds used during construction), including changes in accruals of $115.7 million. Total growth capital expenditures consist of $412.0 million for our midstream and intrastate operations, $78.9 million for our interstate operations, and $39.5 million for our propane operations. We also incurred $102.7 million in maintenance expenditures needed to sustain operations of

 

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which $65.0 million related to midstream and intrastate operations, $13.2 million related to interstate operations, and $24.4 million to propane operations. In addition, we made advances to MEP of $664.5 million and received a reimbursement from FEP of all of our contributions, including $9.0 million that we contributed in 2008. As a result of our acquisition of a natural gas compression equipment business in exchange for ETP Common Units, cash acquired in connection with acquisitions during 2009 exceeded the cash we paid by $30.4 million.

Year Ended December 31, 2008

Cash used in investing activities during the 2008 of $2.02 billion was comprised primarily of cash paid for acquisitions of $84.8 million and $1.92 billion invested for growth capital expenditures (net of contribution in aid of construction costs as discussed in Note 2 to our consolidated financial statements), including changes in accruals of $57.9 million. Total growth capital expenditures consist of $1.19 billion for our intrastate operations, $695.1 million for our interstate operations, and $40.2 million for our propane operations. We also incurred $141.0 million in maintenance expenditures needed to sustain operations of which $75.4 million related to intrastate operations, $25.1 million related to interstate operations, and $40.5 million to propane operations. In addition, we received a reimbursement of $63.5 million, net during the first quarter of 2008 from MEP to the Partnership for previous advances to MEP. There were also advances of $9.0 million made to FEP during the year ended December 31, 2008.

Four Months Ended December 31, 2007

Cash used in investing activities during the four months ended December 31, 2007 of $995.9 million was comprised primarily of cash paid for acquisitions of $337.1 million and $607.7 million invested for growth capital expenditures, including changes in accruals of $5.6 million. Total growth capital expenditures consist of $426.2 million for our intrastate operations and $167.1 million for our interstate operations, and $14.3 million for our propane operations. We also incurred $49.0 million in maintenance expenditures needed to sustain operations of which $21.4 million related to intrastate operations, $12.9 million related to interstate operations, and $14.7 million to propane operations.

Year Ended August 31, 2007

Cash used in investing activities during the year ended August 31, 2007 of $2.16 billion is comprised primarily of cash paid for our investment in CCEH of $1.00 billion (net of the receipt of $49.0 million from CCEH as per the terms of our acquisition agreement), other acquisitions of $90.7 million and $1.02 billion invested for growth capital expenditures (including the payment of $9.4 million accrued in prior periods) of which $985.1 million related to natural gas operations and $32.9 million to propane operations. We also incurred $89.2 million in maintenance expenditures needed to sustain operations of which $63.2 million related to natural gas operations and $26.0 million to propane.

Financing Activities

Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, as discussed below under “Financing and Sources of Liquidity,” which are primarily used to fund our acquisitions and growth capital expenditures. Distributions to partners increase between the periods based on increases in the number of Common Units outstanding and also reflect increases in the declared quarterly distribution per unit, as discussed below under “Cash Distributions.”

Following is a summary of financing activities by period.

Year Ended December 31, 2009

Cash provided by financing activities was $598.6 million for 2009. We received $936.3 million in net proceeds from equity offerings of ETP, including $81.5 million under ETP’s equity distribution program (see Note 7 to our consolidated financial statements). Net proceeds from the equity offerings were used to repay borrowings under the ETP Credit Facility, to fund capital expenditures and capital contributions to joint ventures, as well as for general partnership purposes. During 2009, we had a net increase in our debt level of $522.0 million primarily

 

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due to borrowings to fund capital expenditures and to fund capital contributions to joint ventures, partially offset by the use of proceeds from ETP’s Comm