FORM 10-K
Table of Contents

 

 

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, 2008

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  x    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  x

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  x    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. (Check one)

 

Large accelerated filer   x    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  x

The aggregate market value as of June 30, 2008, 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 approximately $2,784,100,000. 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 19, 2009, the registrant had 222,898,248 Common Units outstanding.

 

 

 


Table of Contents

TABLE OF CONTENTS

PART I

 

          PAGE
ITEM 1.    BUSINESS    2
ITEM 1A.    RISK FACTORS    23
ITEM 1B.    UNRESOLVED STAFF COMMENTS    52
ITEM 2.    PROPERTIES    52
ITEM 3.    LEGAL PROCEEDINGS    53
ITEM 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS    54
PART II
ITEM 5.    MARKET FOR THE REGISTRANT’S COMMON UNITS AND RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES    54
ITEM 6.    SELECTED FINANCIAL DATA    55
ITEM 7.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS    57
ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK    97
ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA    100
ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE    178
ITEM 9A.    CONTROLS AND PROCEDURES    178
ITEM 9B.    OTHER INFORMATION    180
PART III
ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE    180
ITEM 11.    EXECUTIVE COMPENSATION    184
ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS    200
ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE    202
ITEM 14.    PRINCIPAL ACCOUNTANT FEES AND SERVICES    203
PART IV
ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES    204


Table of Contents

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 the Partnership, include certain “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. 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 unit
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 IPO 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 2% General Partner interests and 100% of the Incentive Distribution Rights. 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 Partnerships.

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

 

 

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”), the parent company of Transwestern Pipeline Company, LLC (“Transwestern”) and ETC Midcontinent Express Pipeline, LLC (“ETC MEP”).

 

 

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 2008 Achievements

Our significant 2008 achievements included the following, as discussed in more detail herein:

 

 

The Parent Company received distributions from ETP of $236.3 million, $4.8 million and $305.1 million related to its limited partner interests, general partner interests and Incentive Distribution Rights, respectively.

 

 

On a consolidated basis, we had revenues of approximately $9.29 billion, operating income of approximately $1.10 billion and net income of approximately $375.0 million. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

 

Continued our expansion initiative, completing projects totaling more than 400 miles of large diameter pipeline ranging from 36 inches to 42 inches with approximately 3.9 Bcf/d of natural gas transportation capacity during 2008. These completed pipeline construction projects include:

 

   

The Southeast Bossier pipeline, approximately 157 miles of predominately 42-inch pipe connecting our East Texas and Cleburne to Carthage pipelines with the Texoma pipeline (which is a part of our HPL System) north of Beaumont, Texas.

 

   

The 36-inch Paris Loop pipeline expansion project in North Texas, a 135-mile pipeline connecting our existing pipelines in the Barnett Shale region to our Texoma pipeline in Lamar County, Texas. In the second quarter of 2009, the Paris Loop will connect to the 500-mile Midcontinent Express pipeline.

 

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Expansion of our Cleburne to Carthage pipeline (the “Carthage Loop”) from the Texoma pipeline interconnect to the Carthage Hub through the installation of 32 miles of 42-inch pipeline.

 

   

The 36-inch Maypearl to Malone pipeline which provides a link to an additional 600 MMcf/d of capacity out of the Barnett Shale region.

 

   

The 36-inch San Juan Loop pipeline. The San Juan Loop is the first phase of the previously announced Phoenix Expansion project that also includes the construction of a new 260-mile Phoenix Lateral pipeline designed to serve both residential and industrial customers in the high-growth Phoenix market. The Phoenix Lateral was completed in February of 2009.

 

 

Entered into an agreement for a 50/50 joint development of the Fayetteville Express pipeline, as discussed below under “Recent Developments”.

 

 

Began construction of the Midcontinent Express pipeline, an approximately 500-mile interstate natural gas pipeline that will originate near Bennington, Oklahoma, be routed through Perryville, Louisiana, and terminate at an interconnect with Transco’s interstate natural gas pipeline in Butler, Alabama. The pipeline will have an initial capacity of 1.5 Bcf/d, all of which capacity has been committed pursuant to predominantly 10-year firm transportation contracts with shippers and is expected to be completed and in service through Perryville, Louisiana in the second quarter of 2009. The pipeline has also received long-term transportation contracts related to an additional 0.3 Bcf/d of capacity that is planned to be added through the utilization of additional compression. Midcontinent Express pipeline is a 50/50 joint development with KMP.

 

 

Announced our plans to construct the Texas Independence pipeline, a 160-mile, 42-inch project which will connect to our Carthage Loop. This pipeline is expected to be completed in the third quarter of 2009.

 

 

Completed expansion of the natural gas processing plant in Godley, Texas, increasing the plant capacity to approximately 500 MMcf/d.

 

 

Completed several financing transactions despite challenging market conditions in 2008, including the issuance of $1.5 billion and $600.0 million of ETP Senior Notes in March 2008 and December 2008, respectively, and ETP’s issuance of 7,750,000 ETP Common Units in July 2008. In addition, ETP subsequently raised $225.9 million in proceeds from the issuance of 6,900,000 ETP Common Units in January 2009.

Recent Developments

ETP Enogex Partners LLC

In September 2008, we entered into an agreement with OGE Energy Corp. (“OGE”) to form a joint venture entity, ETP Enogex Partners LLC (“ETP Enogex Partners”), to which OGE would contribute its Enogex midstream business and we would contribute our 100% equity interest in Transwestern, our 50% equity interest in Midcontinent Express Pipeline, LLC (“MEP”), the entity formed to own and operate the Midcontinent Express pipeline, and our 100% equity interest in ETC Canyon Pipeline, LLC, which we refer to as ETC Canyon Pipeline, which owns and operates the Canyon Gathering System. Subsequent to entering into this agreement, conditions in the credit markets deteriorated and the parties were not able to obtain financing on favorable terms. On February 12, 2009, ETP and OGE agreed to terminate the agreement to form a joint venture.

Fayetteville Express Pipeline LLC

In October 2008, we entered into an agreement with KMP for a 50/50 joint development of the Fayetteville Express pipeline, an approximately 187-mile 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. Fayetteville Express Pipeline LLC (“FEP”), the entity formed to own and operate this pipeline, initiated public review of the project pursuant to the FERC’s National Environmental Policy Act (“NEPA”) pre-filing review process of the Federal Energy Regulatory Commission (“FERC”) in November 2008. The pipeline is expected to have an initial capacity of 2.0 Bcf/d. Pending necessary regulatory approvals, the pipeline project is expected to be in service by early 2011. 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 Knight, Inc. (formerly known as Kinder Morgan, Inc.). Knight owns the general partner of KMP. Pursuant to our agreement with KMP related to this project, we and KMP are each obligated to fund 50% of the equity necessary to construct the project.

 

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Tiger Pipeline

On January 27, 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 a 178-mile 42-inch interstate natural gas pipeline (“Tiger pipeline”). The project 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 Tiger pipeline is anticipated to have an initial throughput capacity of at least 1.25 Bcf/d, which capacity may be increased up to 2.0 Bcf/d based on the results of an open season. The agreement with Chesapeake provides for a 15-year commitment for firm transportation capacity of approximately 1.0 Bcf/d. The pipeline project is anticipated to cost between $1.0 billion and $1.2 billion, depending on the final throughput capacity design, with such costs to be incurred over a three-year period. Pending necessary regulatory approvals, the Tiger pipeline is expected to be in service in the first half of 2011.

ETP Operations

Segment Overview and Business Description

Our segments and business are as described below. See Notes 1 and 15 to our consolidated financial statements for additional financial information about our segments for the year ended December 31, 2008.

Natural Gas Operations

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

LOGO

 

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Midstream

Southeast Texas System

 

 

5,000 miles of natural gas pipeline

 

 

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

 

 

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

 

 

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

North Texas System

 

 

160 miles of natural gas pipeline

 

 

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

 

 

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

Canyon Gathering System

 

 

1,360 miles of natural gas pipeline

 

 

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

Intrastate Transportation Pipelines and Storage Facilities

ET Fuel System

 

 

Capacity of 4.1 Bcf/d

 

 

2,680 miles of natural gas pipeline

 

 

2 storage facilities with 12.4 Bcf of total working gas capacity

Oasis pipeline

 

 

Capacity of 1.2 Bcf/d

 

 

600 miles of natural gas pipeline

 

 

Connects Waha to Katy market hubs

Houston pipeline system (“HPL System”)

 

 

Capacity of 5.5 Bcf/d

 

 

4,200 miles of natural gas pipeline

 

 

Bammel storage facility with 62 Bcf of total working gas capacity

East Texas pipeline

 

 

Capacity of 2.0 Bcf/d

 

 

320 miles of natural gas pipeline

Interstate Transportation Pipelines

Transwestern pipeline

 

 

Capacity of 2.1 Bcf/d

 

 

2,700 miles of interstate natural gas pipeline

 

 

Phoenix lateral pipeline – 260 miles of 36-inch and 42-inch pipeline with initial planned capacity of 500 MMcf/d was completed in February 2009

Midcontinent Express pipeline

 

 

Initial planned capacity of 1.5 Bcf/d (expected to be in service in the second quarter of 2009)

 

 

Planned capacity expansion of 0.3 Bcf/d (expected to be in service in the fourth quarter of 2010)

 

 

500 miles of interstate natural gas pipeline

 

 

50/50 joint venture with KMP

Fayetteville Express pipeline

 

 

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

 

 

187 miles of interstate natural gas pipeline

 

 

50/50 joint venture with KMP

 

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Tiger pipeline

 

 

Initial planned capacity of 1.25 Bcf/d (expected to be in service in the first half of 2011)

 

 

178 miles of interstate natural gas pipeline

Midstream Segment

Our midstream business owns and operates approximately 6,700 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.

The midstream segment accounted for approximately 14% of our total consolidated operating income for the year ended December 31, 2008. 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.”

The following is a brief description of the various components of our midstream segment:

 

 

The Southeast Texas System is a 5,000-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 system includes the La Grange processing plant, eleven treating facilities and four conditioning facilities. This system is connected to the Katy Hub through the 320-mile East Texas pipeline and is also connected to the Oasis pipeline, as well as two power plants.

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 eleven 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. 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.

 

 

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, as discussed below.

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. .

 

 

The Canyon Gathering System consists of approximately 1,360 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 aggregated processing capacity of 90 MMcf/d. The system currently gathers approximately 300 MMcf/d from 1,400 wells and is connected to five major pipeline systems.

 

 

The midstream segment also includes our interests in various midstream assets located in Texas, New Mexico and Louisiana, with a combined capacity of approximately 470 MMcf/d.

 

 

Marketing operations, in which we market the natural gas that flows through our assets, referred to as on-system gas, and 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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Substantially all of our on-system marketing efforts involve natural gas that flows through either the Southeast Texas System or our intrastate transportation pipelines. 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.

Intrastate Transportation and Storage Segment

Our intrastate transportation and storage business owns and operates approximately 7,800 miles of natural gas transportation pipelines and three natural gas storage facilities.

Through ETC OLP, we own the largest intrastate pipeline system in the United States with interconnects 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 operations accounted for approximately 65% of our total consolidated operating income for the year ended December 31, 2008. The results from our intrastate transportation and storage segment are primarily derived from the 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 price and resold to customers based on an index price.

The following is a brief description of the various components of our intrastate transportation and storage segment:

 

 

The ET Fuel System, which serves some of the most active drilling areas in the United States, is comprised of approximately 2,680 miles of intrastate natural gas pipeline and related natural gas storage facilities. 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 4.1 Bcf/d.

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. Included in the ET Fuel System is a significant portion of our recently completed Cleburne to Carthage pipeline that connects our North Texas pipeline, a part of our ET Fuel System, our pipelines in the Barnett Shale region, and our Bethel storage facility to our Texoma pipeline in East Texas.

In addition, the ET Fuel System is connected with our Godley plant. This gives us the ability to bypass the plant when processing margins are unfavorable by blending the un-treated natural gas from the North Texas System with natural gas on the ET Fuel System while continuing to meet pipeline quality specifications.

 

 

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:

 

   

providing us with the ability to bypass the La Grange processing plant when processing margins are unfavorable;

 

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providing access for natural gas on the Southeast Texas System to other third party supply and market points and interconnecting pipelines; and

 

   

allowing us to bypass our 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.

 

 

The HPL System is comprised of approximately 4,200 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 and has a particularly strong presence in the key Houston Ship Channel and Katy Hub markets, which significantly contributes to our overall ability to play an important role in the Texas natural gas markets. The HPL System is also well positioned to capitalize upon 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 and has a peak withdrawal rate of 1.3 Bcf/d. The facility also has considerable flexibility during injection periods in that the HPL System has engineered an injection well configuration to provide for a 0.6 Bcf/d peak injection rate. The Bammel storage facility is strategically 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.

During the third quarter of 2008, we completed the expansion of our Cleburne to Carthage pipeline from the Texoma pipeline interconnect to the Carthage Hub through the installation of 32 miles of 42-inch pipeline. This expansion, which we refer to as the Carthage Loop, added 500 MMcf/d of pipeline capacity from Cleburne to the Carthage Hub.

 

 

The East Texas pipeline is a 320-mile natural gas pipeline that connects three treating facilities, one of which we own, with our Southeast Texas System. This 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 expansion had an initial capacity of over 400 MMcf/d which increased to the current capacity of 2.0 Bcf/d with the addition of the Grimes County Compressor Station.

Interstate Transportation Segment

Our interstate transportation segment accounted for approximately 11% of our total consolidated operating income for the year ended December 31, 2008. The results from our interstate transportation segment are primarily derived from the fees earned from natural gas transportation services and operational gas sales. Our interstate transportation operation began in fiscal 2007 with the acquisition of the Transwestern pipeline.

The following is a brief description of the various components of our interstate transportation segment:

 

 

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 recently completed projects listed below, 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 and is subject to the regulatory jurisdiction of the Federal Energy Regulatory Commission (“FERC”). The operating results for Transwestern are included in our results on a consolidated basis as of the acquisition date (December 1, 2006).

 

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During fiscal year 2007, we initiated the Phoenix project, consisting of 260 miles of 42-inch and 36-inch 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. The Phoenix project, as filed with the FERC on September 15, 2006, includes the construction and operation of approximately 260 miles of 36-inch or larger diameter pipeline extending from Transwestern’s existing mainline in Yavapai County, Arizona to delivery points in the Phoenix, Arizona area and certain looping on Transwestern’s existing San Juan Lateral with approximately 25 miles of 36-inch diameter pipeline. The San Juan Lateral portion of the project was placed in service effective July 2008. On February 20, 2009, FERC authorized Transwestern to commence service on the Phoenix lateral.

 

 

We are currently constructing, 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 will originate near Bennington, Oklahoma, be routed through Perryville, Louisiana, and terminate 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 will have an initial capacity of 1.5 Bcf/d, all of which capacity has been committed pursuant to predominantly 10-year firm transportation contracts with shippers. The pipeline has also received long-term transportation contracts related to an additional 0.3 Bcf/d of capacity that is planned to be added through the utilization of additional compression. Mobilization for construction of this pipeline commenced in September 2008, following FERC approval. The first phase of the pipeline is expected to be in service by the second quarter of 2009 and the second phase of the pipeline is expected to be in service by the third quarter of 2009. Certain regulatory approvals are still pending with respect to the expansion and interim service of Midcontinent Express pipeline. We account for this joint venture using the equity method, as further discussed in our consolidated financial statements.

 

 

In October 2008, we entered into an agreement with KMP for a 50/50 joint development of Fayetteville Express pipeline, an approximately 187-mile natural gas 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. FEP, the entity formed to own and operate this pipeline, initiated public review of the project pursuant to the FERC’s NEPA pre-filing review process in November 2008. The pipeline is expected to have an initial capacity of 2.0 Bcf/d. Pending necessary regulatory approvals, the pipeline project is expected to be in service by early 2011. FEP has secured binding 10-year commitments for transportation of approximately 1.85 Bcf/d. The new pipeline will interconnect with 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 Knight, Inc. Knight, Inc. owns the general partner of KMP. Pursuant to our agreement with KMP related to this project, we and KMP are each obligated to fund 50% of the equity necessary to construct the project. We account for this joint venture using the equity method, as further discussed in our consolidated financial statements.

 

 

On January 27, 2009 we announced that we had entered into an agreement with Chesapeake Energy Marketing, Inc., a wholly-owned subsidiary of Chesapeake to construct the Tiger pipeline, a 178-mile 42-inch interstate natural gas pipeline. The 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, and interconnect with at least seven interstate pipelines at various points in Louisiana.

The Tiger pipeline is anticipated to have an initial throughput capacity of at least 1.25 Bcf/d, which capacity may be increased up to 2.0 Bcf/d based on the results of an open season. The agreement with Chesapeake provides for a 15-year commitment for firm transportation capacity of approximately 1.0 Bcf/d. The pipeline project is anticipated to cost between $1.0 billion and $1.2 billion, depending on the final throughput capacity design, with such costs to be incurred over a three-year period. Pending necessary regulatory approvals, the Tiger pipeline is expected to be in service in the first half of 2011.

Retail Propane Segment

We are one of the three largest retail propane marketers in the United States, based on gallons sold. We serve more than one million customers from approximately 440 customer service locations in approximately 40 states. Our propane operations extend from coast

 

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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 operations accounted for approximately 10% of our total consolidated operating income for the year ended December 31, 2008. The retail propane segment is a margin-based business in which gross profits depend on the excess of sales price over propane supply cost. The market price of propane is often subject to volatile changes as a result of supply or other market conditions over which we have no control. We have generally been successful in maintaining retail gross margins on an annual basis despite changes in the wholesale cost of propane, but there is no assurance that we will always be able to pass on product cost increases fully, particularly when product costs rise rapidly. Consequently, our profitability will be sensitive to changes in wholesale propane prices.

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 not only affected by weather patterns, but also vary according to 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.

Business Strategy and Competitive Strengths

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 and Strengths

ETP’s primary objective is to increase 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.

 

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We expect that acquisitions in natural gas operations will be the primary focus of our acquisition strategy going forward, as evidenced by the Transwestern pipeline and Canyon Gathering System acquisitions, 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.

We believe that we are well-positioned to compete in both the natural gas operations and retail propane industries based on the following strengths:

 

 

We believe that the size and scope of our operations, our stable asset base and cash flow profile, and our investment grade status will be significant positive factors in our efforts to obtain new debt or equity financing in light of current market conditions, as evidenced by ETP’s public debt offering in December 2008 of $600.0 million aggregate principal amount of 9.70% Senior Notes due 2019 and ETP’s public equity offering in January 2009 of 6,900,000 ETP Common Units which provided us with aggregate net proceeds of approximately $821.9 million. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Financing and Sources of Liquidity”.

 

 

Our experienced management team has an established reputation as highly effective, strategic operators within our operating segments. In addition, our management team is motivated to effectively and efficiently manage our business operations through performance-based incentive compensation programs and has a substantial equity ownership in us.

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.

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 and transportation 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.

Natural Gas Operations Business Strengths

Our assets provide marketing flexibility through our access to numerous markets and customers. Through the combination of strategic acquisitions and substantial investments in internal growth projects and expansions, we have engineered our pipeline system to be well-positioned to service major North American natural gas producing basins. Our assets provide our customers direct access to the Waha and Katy Hubs and to virtually all other market areas in the United States via interconnections with major intrastate and interstate natural gas pipelines. Furthermore, our assets are tied directly or indirectly to a number of major power generation facilities in Texas as well as several industrial and utility end-users. With the acquisition of the ET Fuel System in June 2004, the HPL System acquisition in January 2005, and the completion of several intrastate pipeline construction projects in Texas over the last three years, we have also increased our access to additional power plants, industrial users, municipalities, and co-operatives, and the added storage facilities add flexibility for fuel management services. The completion of an expansion of the Cleburne to Carthage pipeline and the completion of the Southern Shale pipeline, the Southeast Bossier pipeline, the Paris Loop pipeline and the Maypearl to Malone pipeline provides producers with firm capacity out of the Barnett Shale, the Bossier Sands, the Permian Basin, and other major producing areas to all major market hubs in Texas and numerous interstate pipelines. We also provide our customers with additional firm access to west coast and the Phoenix markets with the acquisition of the Transwestern pipeline and the completion of the Phoenix lateral.

 

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We have a significant market presence in each of our operating areas. We have a significant market presence in each of our operating areas, which are located in major natural gas producing regions of the United States including north Texas (Barnett Shale), east Texas (Bossier), west Texas (Permian Basin), the Texas Gulf Coast, the Texas Panhandle, and the Rocky Mountains.

Our ability to bypass our La Grange and Godley processing plants reduces our commodity price risk. A significant benefit of our ownership of the Oasis pipeline and ET Fuel System is that we can elect not to process natural gas at our processing plants when processing margins (or the difference between NGL sales prices and the cost of natural gas) are unfavorable. Instead of processing the natural gas, we are able to deliver natural gas meeting pipeline quality specifications by blending rich gas, or gas with a high NGL content, from the Southeast Texas System or North Texas System with lean gas, or gas with a low NGL content, transported on the Oasis pipeline or ET Fuel System. This enables us to sell the blended natural gas for a higher price than we would have been able to realize upon the sale of NGLs if we had to process the natural gas to extract NGLs.

The HPL System enables us to engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time. The Bammel natural gas storage facility, acquired when we purchased the HPL System, has a total working gas capacity of approximately 62 Bcf. The reservoir has a peak withdrawal rate of 1.3 Bcf/d and also has considerable flexibility during injection periods in that the HPL System has engineered an injection well configuration to provide for a 0.6 Bcf/d peak injection rate. Therefore, we are able to purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. In addition, the Bammel natural gas storage facility is strategically 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.

Propane Business Strategies

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.

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.

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

Propane Business Strengths

Geographically diverse retail propane network. We believe our geographically diverse network of retail propane assets reduces our exposure to unfavorable weather patterns and economic downturns in any one geographic region, thereby reducing the volatility of our cash flows.

Operations that are focused in areas experiencing higher-than-average population growth. We believe that our concentration in higher-than-average population growth areas provides a strong economic foundation for expansion through acquisitions and internal growth. We do not believe that we are more vulnerable than our competitors to displacement by natural gas distribution systems because the majority of our operations are located in rural areas where natural gas is not readily available.

Experience in identifying, evaluating and completing acquisitions. We follow a disciplined acquisition strategy that concentrates on propane companies that (1) are located in geographic areas experiencing higher-than-average population growth, (2) provide a high percentage of sales to residential customers, (3) have a strong reputation for quality service, and (4) own a high percentage of the propane tanks used by their customers. In addition, we attempt to capitalize on the reputations of the companies we acquire by maintaining local brand names, billing practices and employees, thereby creating a sense of business continuity which minimizes customer loss. We believe that this strategy has also helped to make us an attractive buyer for many propane acquisition candidates from a seller’s viewpoint.

 

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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 2008 by the Energy Information Administration, or the EIA, total domestic consumption of natural gas is expected to remain steady through 2030, with average annual consumption of 23.6 Tcf during that period, compared to 2008 consumption of 23.4 Tcf. The industrial and electricity generation sectors currently account for more than half of natural gas usage in the United States.

Natural gas gathering. The natural gas gathering process begins with the drilling of wells into gas bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems generally consist of a network of small diameter pipelines and, if necessary, compression systems that collect natural gas from points near producing wells and transport it to larger pipelines for further transportation.

Natural gas compression. Gathering systems are operated at design pressures that will maximize the total throughput from all connected wells. Specifically, lower pressure gathering systems allow wells, which produce at progressively lower field pressures as they age, to remain connected to gathering systems and to continue to produce for longer periods of time. As the pressure of a well declines, it becomes increasingly 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 would 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

 

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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 minimize 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 consist primarily of financial institutions, major energy companies and local distribution companies (“LDCs”). 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.

Current economic conditions also indicate that many of our customers may encounter increased credit risk in the near term. In particular, 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. 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 sale price. Therefore, a credit loss could be significant to our overall profitability.

During the year ended December 31, 2008, none of our customers individually accounted for more than 10% of our midstream, intrastate transportation and storage and interstate segment revenues.

Regulation

Regulation by Federal Energy Regulatory Commission (“FERC”) of Interstate Natural Gas Pipelines. FERC has broad regulatory authority over the business and operations of interstate natural gas pipelines. Under the Natural Gas Act (“NGA”), FERC generally regulates the transportation of natural gas in interstate commerce. For FERC regulatory purposes, “transportation” includes natural gas pipeline transmission (forwardhauls and backhauls), storage, and other services. The Transwestern pipeline transports natural gas in interstate commerce and thus qualifies as a “natural gas company” under the NGA subject to FERC’s regulatory jurisdiction. We also hold interests in two joint venture projects involving the construction and operation of interstate pipelines: Midcontinent Express pipeline and Fayetteville Express pipeline. When completed and placed into operation, these pipeline systems will also be NGA-jurisdictional interstate transportation systems subject to the FERC’s broad regulatory oversight.

FERC’s NGA authority includes the power to regulate:

 

 

the certification and construction of new facilities;

 

 

the review and approval of cost-based transportation rates;

 

 

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

 

 

the terms and conditions associated with these services;

 

 

the extension or abandonment of services and facilities;

 

 

the maintenance of accounts and records;

 

 

the acquisition and disposition of facilities; and

 

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the initiation and discontinuation of services.

Under the NGA, interstate natural gas companies must charge rates that are just and reasonable. In addition, the NGA prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

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, 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 to be charged on the Midcontinent Express pipeline will largely be governed by long-term negotiated rate agreements, an arrangement approved by FERC in its July 25, 2008 order granting Midcontinent Express pipeline the certificate of public convenience and necessity to build, own and operate these facilities. In the certificate order, 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 Fayetteville Express pipeline project has not yet been filed with FERC, hence the rates to be charged for services provided on that facility have not yet been established.

The rates to be charged by NGA-jurisdictional natural gas companies are generally required to be on file with 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 FERC. Rate increases proposed by the interstate natural gas company may be challenged by protest or by FERC itself, and if such proposed rate increases are found unjust and unreasonable may be rejected by 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 assure you that 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, 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 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. With regard to our physical purchases and sales of natural gas, NGLs or other energy commodities; our gathering or 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 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

 

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commerce, the rates, terms and conditions of such services are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act (“NGPA”). The NGPA regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. The rates, terms and conditions of some transportation and storage services provided on the Oasis pipeline, HPL System, East Texas pipeline and ET Fuel System are subject to FERC regulation pursuant to Section 311 of the NGPA. Under Section 311, rates charged for intrastate transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The terms and conditions of service set forth in the intrastate facility’s statement of operating conditions are also subject to FERC review and approval. Should 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 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.

FERC has adopted new 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 FERC’s NGA jurisdiction. 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. FERC has also proposed to require certain major non-interstate pipelines to post, on a daily basis, capacity, scheduled flow information and actual flow information. These posting requirements are not administratively final, thus it is not known with certainty the precise form these requirements will ultimately take. Depending upon the breadth of FERC’s final rules, these regulations could subject us to further costs and administrative burdens.

Our intrastate natural gas operations in Texas are also subject to regulation by various agencies in Texas, principally the Texas Railroad Commission (“TRRC”), where they are located. 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.

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. 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 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 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 FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services 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 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.

 

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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 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.

 

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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 of converting 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 retail propane distribution business. 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

We distribute propane through a nationwide retail distribution network consisting of approximately 440 customer service locations in approximately 40 states, concentrated in large part in the western, upper midwestern, northeastern and southeastern regions of the United States.

Typically, customer service locations are found 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, approximately 55% were to residential customers, 30% were to industrial, commercial and agricultural customers, and 15% were to other retail users. Sales to residential customers in the year ended December 31, 2008 accounted for 55% of total retail gallons sold but accounted for approximately 70% 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 the year ended December 31, 2008, with all other retail users accounting for 9%. No single customer accounts for 10% or more of consolidated revenues.

 

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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 50 energy companies and natural gas processors at numerous supply points located in the United States and Canada. In the year ended December 31, 2008, Enterprise Products Operating L.P. (“Enterprise”) and Targa Liquids (“Targa”) provided approximately 50.7%, and 15.0% 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 substantially all of its propane from Enterprise pursuant to an agreement that expires in 2010. Additionally, HOLP has a monthly storage contract with TEPPCO Partners, L.P. (an affiliate of Enterprise).

In addition, we have a seven-year propane purchase agreement with M.P. Oils, Ltd. (see Note 10 to our consolidated financial statements), which provided 14.9% of our combined total propane supply during the year ended December 31, 2008.

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 the year ended December 31, 2008. Although we cannot assure you 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 supply agreement and the agreement with 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, and 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 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.

 

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Environmental Matters

The operation of pipelines, plants and other facilities for gathering, compressing, treating, processing, or transporting natural gas, natural gas liquids 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:

 

 

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

 

 

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

 

 

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

 

 

imposing substantial liabilities on us for pollution resulting from our operations, including, for example, potentially enjoining the operations of facilities if it were determined that they were not in compliance 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 assure you 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.

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 will 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

 

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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, 2008 an accrual of $13.3 million was recorded in our consolidated balance sheet 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 approximately $9.1 million. Transwestern received FERC approval for rate recovery of projected soil and groundwater remediation costs not related to PCBs effective April 1, 2007.

Transwestern continues to incur certain costs related to PCBs that could migrate through its pipelines into customers’ facilities. Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing the PCBs. Costs of these remedial activities totaled approximately $0.8 million for the period since acquisition. Future costs cannot be reasonably estimated because remediation activities are undertaken as potential claims are made by customers and former customers, and accordingly, no accrual has been established for these costs at December 31, 2008. However, such future costs are not expected to have a material impact on our financial position, results of operations or cash flows.

The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state and federal waters. The discharge of pollutants into regulated waters is prohibited, except in accord with the terms of a permit issued by EPA or the state. Any unpermitted release of pollutants, including NGLs or condensates, from our systems or facilities 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 received a state-issued “Pipeline Facilities” air emissions permit on June 30, 2005 for our Prairie Lea Compressor Station in Caldwell County, Texas, which historically has been designated as a “grandfathered facility” and, thus, was excluded from state air emissions permitting requirements. We currently comply with the terms of this permit and associated regulations requiring specified reductions in nitrogen oxides or “NOx” emissions. During 2006 and 2007 we spent an estimated $3.0 million to modify the compressor engines at the facility. In addition, 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 is currently developing a plan to respond to the re-designation of the Houston area from a moderate to a severe ozone non-attainment area, and later it will develop another plan to address the recent change in the ozone standard from 0.08 ppm to 0.075 ppm. We expect these efforts will result in the adoption of new regulations that may require additional NOx emissions reductions.

 

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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, President Obama has expressed support for, and it is anticipated that the current session of Congress will consider, legislation to restrict or regulate emissions of greenhouse gases. In addition, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas “cap and trade” programs. These “cap and trade” programs could require major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries or gas processing plants that emit more greenhouse gases than permitted by these programs, to acquire emission allowances from other businesses that emit greenhouse gases at levels lower than the limits specified by these programs and then surrender these allowances as a credit against such emissions. Depending on the particular program, we could be required to purchase and surrender such 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) 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, the EPA may regulate greenhouse gas emissions from mobile sources such as cars and trucks even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases, including carbon dioxide, fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources. In July 2008, EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act, in response to the Supreme Court’s decision in Massachusetts. In the notice, EPA evaluated the potential regulation of greenhouse gases under the Clean Air Act and other potential methods of regulating greenhouse gases. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such new federal, regional or state restrictions on emissions of carbon dioxide or other greenhouse gases that may be imposed in areas in which we conduct business could also have an adverse affect on our cost of doing business and demand for the natural gas we process and transport.

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. Through December 31, 2008, Transwestern did not incur any costs associated with the IMP Rule and has satisfied all of the requirements until 2009. Through December 31, 2008, a total of $16.4 million of capital costs and $12.7 million of operating and maintenance costs have been incurred for pipeline integrity testing for our transportation assets other than Transwestern. Through December 31, 2008, a total of $6.9 million of capital costs and $0.4 million of operating and maintenance costs have been incurred for pipeline integrity costs for Transwestern. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of 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 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

 

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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.

Employees

As of February 6, 2009, we employed 1,153 people to operate our natural gas operation segments. We employ 4,277 full-time employees to operate our propane segments. Of the propane employees, 84 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 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 to our periodic and current reports on our Internet website, http://www.energytransfer.com, free of charge. These reports are available on our website as soon as reasonably practicable after we electronically file such materials with the SEC. Information contained on our website is not part of this report.

ITEM 1A. RISK FACTORS

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

 

 

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

 

 

the level of throughput in its processing and treating operations;

 

 

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

 

 

the price of natural gas;

 

 

the relationship between natural gas and NGL prices;

 

 

the weather in its operating areas;

 

 

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

 

 

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

 

 

the level of its operating costs;

 

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prevailing economic conditions; and

 

 

the level of ETP’s hedging activities.

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

 

 

the level of capital expenditures it makes;

 

 

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

 

 

the cost of acquisitions, if any;

 

 

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

 

 

its debt service requirements;

 

 

fluctuations in its working capital needs;

 

 

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

 

 

its ability to access capital markets;

 

 

restrictions on distributions contained in its debt agreements; and

 

 

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

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, you 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:

 

 

interest expense and principal payments on our indebtedness;

 

 

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

 

 

our general and administrative expenses;

 

 

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

 

 

capital contributions to maintain our 2% general partner interest in ETP as required by the partnership agreement of ETP upon the issuance of additional partnership securities by ETP; and

 

 

reserves our General Partner believes prudent for us to maintain for the proper conduct of our business or to provide for future distributions.

We cannot guarantee that in the future we will be able to pay distributions or that any distributions we do make will be at or above our current quarterly distribution. The actual amount of cash that is available for distribution to our Unitholders will depend on numerous factors, many of which are beyond our control or the control of our General Partner.

 

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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 affiliates of our general partner (including Enterprise GP Holdings L.P.) own 39,768,401 Common Units, representing approximately 18% of our outstanding Common Units, it will be particularly difficult for our general partner to be removed without the consent of such 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 direct and indirect ownership of 100% of the incentive distribution rights in ETP (50% prior to November 1, 2006), 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. The amount of the cash distributions that we received from ETP during our fiscal year 2006 related to our ownership interest in the incentive distribution rights has increased at a more rapid rate than the amount of the cash distributions related to our 2% General Partner interest in ETP and our ETP Common Units. 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 2% 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, 2008, we had approximately $7.24 billion of consolidated debt outstanding. Our level of indebtedness affects our operations in several ways, including, among other things:

 

 

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;

 

 

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;

 

 

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

 

 

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

 

 

failure to comply with the various restrictive and affirmative covenants of the credit agreements could negatively impact our ability and the ability of our subsidiaries to incur additional debt and to pay distributions. We are required to measure these financial tests and covenants quarterly and, as of December 31, 2008, we were in compliance with all financial requirements, tests, limitations, and covenants related to financial ratios under our existing credit agreements.

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, 2008, ETP had approximately $5.66 billion of consolidated debt outstanding. 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, 2008, we had approximately $7.24 billion of consolidated debt, of which approximately $4.76 billion was at fixed interest rates and approximately $2.48 billion was at variable interest rates. We have entered interest rate swaps for a total notional amount of $2.13 billion, resulting in a net amount of $0.35 billion of variable-rate debt at December 31, 2008. 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. During the three months ended December 31, 2008, ETP entered into forward starting interest rate swaps with a notional amount of $500.0 million for a forecasted debt issuance by the end of 2009. These swaps were not designated as cash flow hedges; therefore, changes in interest rates could adversely affect ETP’s and our results of operations until the forecasted debt is issued and could require a cash payment upon settlement.

Increases in interest rates may cause a corresponding decline in demand for yield-based equity investments such as our Common Units.

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 its indirect owner 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.

 

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We may issue an unlimited number of limited partner interests without the consent of our Unitholders, which will dilute your ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.

Our partnership agreement allows us to issue an unlimited number of additional limited partner interests, including securities senior to the Common Units, without the approval of our Unitholders. The issuance of additional Common Units or other equity securities by us will have the following effects:

 

 

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

 

 

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

 

 

the ratio of taxable income to distributions may increase;

 

 

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

 

 

the market price of our Common Units may decline.

In addition, ETP 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 Mackie McCrea, President and Chief Operating Officer, and William G. Powers, 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.

 

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ETP’s executive officers that provide services to us pursuant to a shared services agreement allocate their time between us and ETP. To the extent that these officers face conflicts regarding the allocation of their time, we may not receive the level of attention from them that the management of our business requires. If ETP is unable to provide us with a sufficient number of personnel with the appropriate level of technical accounting and financial expertise, our internal accounting controls could be adversely impacted.

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

Like all equity investments, an investment in our units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our units to decline.

Your liability as a limited partner 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, you could be held liable for our obligations to the same extent as a general partner if you participate 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. You could, however, be liable for any and all of our obligations as if you were a general partner if:

 

 

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

 

 

your right to act with other Unitholders to 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 in the future we cease to manage and control ETP, 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.

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.

 

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

 

 

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

 

 

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

 

 

makes a general assignment for the benefit of creditors, files a voluntary bankruptcy petition, seeks to liquidate, acquiesces in the appointment of a trustee, receiver or liquidator, or becomes subject to an involuntary bankruptcy petition; or

 

 

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

In addition, ETP GP 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 units (including units held by ETP GP and its affiliates).

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.

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, 2008, 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

 

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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, 2008, our consolidated balance sheet reflected $773.3 million of goodwill and $215.9 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.

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

 

 

the allocation of shared overhead expenses to ETP and us;

 

 

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

 

 

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;

 

 

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

 

 

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.

 

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Affiliates of our General Partner are not prohibited from competing with us.

Our partnership agreement provides that our General Partner will be restricted from engaging in any business activities other than acting as our General Partner and those activities incidental to its ownership of interests in us. Except as provided in our partnership agreement, affiliates of our General Partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Enterprise GP Holdings L.P. currently has a 40.6% non-controlling equity interest in our General Partner. Enterprise GP Holdings L.P. 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:

 

 

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 duty to our Unitholders.

 

 

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.

 

 

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.

 

 

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

 

 

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

 

 

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

 

 

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

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:

 

 

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

 

 

provides that our General Partner is entitled to make other decisions in “good faith” if it reasonably believes that the decisions are in our best interests;

 

 

generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the Audit and Conflicts Committee of the board of directors of our General Partner and not involving a vote of Unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our General Partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

 

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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 you to sell your 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, you may be required to sell your units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. As of December 31, 2008, affiliates of our General Partner excluding Enterprise GP Holdings, L.P. own approximately 31.6% of our Common Units.

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, or 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 ETP units, which may increase the risk that ETP will not have sufficient Available Cash to maintain or increase its per unit distribution level.

ETP has wide latitude to issue additional units on terms and conditions established by its General Partner. The payment of distributions on those and additional units 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 distribute to our Unitholders.

The issuance of additional Common Units or other equity securities of equal rank will have the following effects:

 

 

our Unitholders’ proportionate ownership interest in ETP will decrease;

 

 

the amount of cash available for distribution on each Common Unit may decrease; and

 

 

the market price of our Common Units may decline.

Furthermore, ETP’s partnership agreement does not give our Unitholders the right to approve our issuance of equity securities.

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.

 

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ETP may not be able to obtain funding on acceptable terms or at all under its revolving credit facility or otherwise because of the deterioration of the credit and capital markets. This may hinder or prevent ETP from meeting future capital needs.

Global financial markets and economic conditions have been, and continue to be, disrupted and volatile due to a variety of factors, including significant write-offs in the financial services sector and the current weak economic conditions. As a result, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets has diminished significantly. In particular, as a result of concerns about the stability of financial markets generally and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt on similar terms or at all and reduced, or in some cases ceased, to provide funding to borrowers. In addition, lending counterparties under existing revolving credit facilities and other debt instruments may be unwilling or unable to meet their funding obligations. Due to these factors, ETP cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, ETP may be unable to meet its obligations as they come due or ETP may be required to post collateral to support its obligations. Moreover, without adequate funding, ETP may be unable to execute its growth strategy, complete future acquisitions or announced and future pipeline construction projects, take advantage of other business opportunities or respond to competitive pressures, any of which could have a material adverse effect on ETP’s revenues and results of operations.

Many of ETP’s customers’ drilling activity levels and spending for transportation on ETP’s pipeline system may be impacted by the current deterioration in commodity prices and the credit markets.

Many of ETP’s customers finance their drilling activities through cash flow from operations, the incurrence of debt or the issuance of equity. Recently, there has been a significant decline in the credit markets and the availability of credit. Additionally, many of ETP’s customers’ equity values have substantially declined. The combination of a reduction of cash flow resulting from recent declines in natural gas prices, a reduction in borrowing base under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction in ETP’s customers’ spending for natural gas drilling activity, which could result in lower volumes being transported on ETP’s pipeline systems. For example, a number of ETP’s customers have announced reduced drilling capital expenditure budgets for 2009. A significant reduction in drilling activity could have a material adverse effect on ETP’s operations.

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 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 effect on ETP’s results of operations and operating cash flows.

The FERC is pursuing legal action against ETP relating to certain natural gas trading and transportation activities, and related third party actions have been filed against us and ETP.

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 has 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 its index-priced physical gas purchases in the Houston Ship Channel. The FERC has 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”). ETP allegedly 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. Additionally, the FERC has alleged that ETP manipulated daily prices at the Waha and Permian Hubs in west Texas on two dates.

 

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ETP’s Oasis pipeline transports interstate natural gas pursuant to Natural Gas Policy Act (“NGPA”) Section 311 authority and is subject to the FERC-approved rates, terms and conditions of service. The allegations related to the Oasis pipeline include claims that the Oasis pipeline violated NGPA regulations from January 26, 2004 through June 30, 2006 by granting undue preference to its affiliates for interstate NGPA Section 311 pipeline service to the detriment of similarly situated non-affiliated shippers and by charging in excess of the FERC-approved maximum lawful rate for interstate NGPA Section 311 transportation. On October 29, 2008, ETP moved for summary disposition of the claim that Oasis unduly discriminated against non-affiliated shippers and unduly preferred affiliated shippers. The presiding administrative law judge granted this motion on November 18, 2008, holding that FERC Staff had failed to make a prima facie case in support of this claim. This ruling, if allowed to stand, significantly narrows the FERC’s Oasis-related claims in the Order and Notice proceeding. The FERC also seeks 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, which activity is expected to account for approximately 1.0% of ETP’s operating income for our 2008 year. If the FERC is successful in revoking ETP’s blanket marketing authority, ETP’s sales of natural gas at market-based prices would be limited to sales to retail customers (such as utilities and other end-users) and sales from its own production, and any other sales of natural gas by ETP would be required to be made at contract prices that would be subject to individual FERC approval.

In its Order and Notice, the FERC is seeking $70.1 million in disgorgement of profits, plus interest, and $97.5 million in civil penalties relating to these matters. The FERC has taken the position that, once it receives ETP’s response, it has several options as to how to proceed, including issuing an order on the merits, requesting briefs, or setting specified issues for a trial-type hearing before an administrative law judge. On August 27, 2007, ETP filed a request for rehearing of the Order and Notice. On December 20, 2007, the FERC issued an order denying rehearing and directed the FERC Enforcement Staff to file a brief recommending disposition of issues by order or by evidentiary hearing. ETP filed its response to the Order and Notice with the FERC on October 9, 2007, which response refuted the FERC’s claims and requested a dismissal of the FERC proceeding. On February 14, 2008, the Enforcement Staff of the FERC filed a brief recommending that the FERC refer various matters relating to its market manipulation allegations for an evidentiary hearing before a FERC administrative law judge. The Enforcement Staff also recommended that FERC issue an order assessing the $15.5 million portion of the above-referenced penalty against ETP with respect to the allegations related to ETP’s Oasis pipeline and that the Oasis-related penalty assessment, if not paid, then be referred by the FERC to a federal district court for de novo review. The Enforcement Staff also recommended that the FERC impose certain changes in Oasis’ business operations and refunds to certain Oasis customers as previously proposed in the Order and Notice. Finally, the Enforcement Staff 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 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. If the FERC pursues the claims related to this additional month, the total amount of civil penalties and disgorgement of profits sought by the FERC would be approximately $200.0 million. On March 31, 2008, we responded to the Enforcement Staff’s brief. On May 15, 2008, the FERC ordered hearings to be conducted by FERC administrative law judges with respect to the FERC’s Oasis claims and market manipulation claims. The hearing related to the Oasis claims was scheduled to commence in December 2008 with the administrative law judge’s initial decision due by May 11, 2009, however, as discussed below, ETP entered into a settlement agreement with FERC Enforcement Staff and that agreement was approved by the FERC in its entirety and without modification on February 27, 2009. The hearing related to the market manipulation claims is now scheduled to commence in June 2009 with the administrative law judge’s initial decision due by December 3, 2009. The FERC also ordered that, following the completion of the hearings, the administrative law judges make initial findings with respect to whether we engaged in market manipulation in violation of the NGA and FERC regulations and whether Oasis violated the NGPA and FERC regulations. The FERC reserved for itself the issues of possible civil penalties, revocation of our blanket market certificate, the method by which we and Oasis would disgorge any unjust profits and whether any conditions should be placed on Oasis’s Section 311 authorization. Following the issuance of each of the administrative law judge’s initial decisions, the FERC would then issue an order with respect to each of these matters. On May 23, 2008, we requested rehearing and stay of the FERC’s May 15, 2008 order establishing hearing, and we renewed those requests on June 26, 2008. On August 7, 2008, FERC denied rehearing of its May 15, 2008 order. On August 8, 2008, we filed a petition with the U.S. Court of Appeals for the Fifth Circuit to review and set aside FERC’s May 15 and August 7, 2008 orders on the grounds that we are entitled to adjudicate FERC’s claims in federal district court pursuant to the NGA and the NGPA. On August 28, 2008, we filed an amended petition seeking review of the Order and Notice and the December 20, 2007 order denying rehearing.

On November 18, 2008, the administrative law judge presiding over the Oasis claims granted ETP’s motion for summary disposition of the claim that Oasis unduly discriminated in favor of affiliates regarding the provision of Section 311(a)(2) interstate transportation service. ETP subsequently entered into an agreement with the Enforcement Staff to settle all of the claims related to Oasis. On January 5, 2009, this agreement was submitted under seal to FERC by the presiding administrative law judge, for FERC’s approval as

 

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an uncontested settlement of all Oasis claims. On February 27, 2009, the settlement agreement was approved by the FERC in its entirety and without modification and the terms of the settlement were made public. If no person seeks rehearing of the order approving the settlement within 30 days of such order, the FERC’s order will become final and non-appealable. We do not believe the Oasis settlement, as approved by the FERC, will have a material adverse effect on our business, financial condition or results of operations.

It is ETP’s position that its trading and transportation activities during the periods at issue complied in all material aspects with applicable law and regulations, and ETP intends to contest these cases vigorously. However, the laws and regulations related to alleged market manipulation are vague, subject to broad interpretation, and offer little guiding precedent, while at the same time the FERC holds substantial enforcement authority. At this time, neither we nor ETP is able to predict the final outcome of these matters.

On July 26, 2007, the United States Commodity Futures Trading Commission (the “CFTC”) filed suit in United States District Court for the Northern District of Texas alleging that we violated provisions of the Commodity Exchange Act (the “CEA”) by attempting to manipulate natural gas prices in the Houston Ship Channel. On March 17, 2008, ETP entered into a consent order with the CFTC (the “Consent Order”). Pursuant to the Consent Order, ETP agreed to pay the CFTC $10.0 million and the CFTC agreed to release ETP and its affiliates, directors and employees from all claims or causes of action asserted by the CFTC in this proceeding. The Consent Order provides that ETP is permanently enjoined from attempting to manipulate the price of any commodity in interstate commerce in violation of the CEA. By consenting to the entry of the Consent Order, ETP neither admitted nor denied the allegations made by the CFTC in this proceeding. The settlement reduced our existing accrual and was paid from cash flow from operations in March 2008.

In addition to the FERC legal action, third parties have asserted claims and may assert additional claims against us and ETP for damages related to these matters. In this regard, several natural gas producers and a natural 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 and ETP’s 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. One such case currently is on appeal before the Texas Supreme Court on, among other things, the issue of whether the dispute is arbitrable.

We have also been 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 producers/operators, seeking arbitration to recover damages based on alleged manipulation of natural gas prices at the Houston Ship Channel. We 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. The claimants have filed a notice of appeal.

A consolidated class action complaint has been 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 New York Mercantile Exchange, or NYMEX, in violation of the CEA. It is further alleged that during the class period December 29, 2003 to December 31, 2005, ETP had the market power to manipulate index prices, and that it 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 its 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 June 19, 2008 the plaintiffs filed a response opposing ETP’s motion to dismiss. ETP filed a reply in support of its motion on July 9, 2008.

 

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On March 17, 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 from its 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 relief. On May 19, 2008, ETP filed a motion to dismiss this complaint. On July 2, 2008 the plaintiffs filed a response opposing ETP’s motion to dismiss. ETP filed a reply in support of our motion on August 18, 2008.

We are expensing the legal fees, consultants’ fees and other expenses relating to these matters in the periods in which such expenses are incurred. In addition, our existing accruals for litigation and contingencies include an accrual related to these matters. At this time, we are unable to predict the outcome of these matters. However, it is possible that the amount we become obliged to pay as a result of the final resolution of these matters, whether on a negotiated settlement basis or otherwise, will exceed the amount of our existing accrual related to these matters. In accordance with applicable accounting standards, we will review the amount of our accrual related to these matters as developments related to these matters occur and we will adjust our accrual if we determine that it is probable that the amount we may ultimately become obliged to pay as a result of the final resolution of these matters is greater than the amount of our existing accrual for these matters. As our 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 our cash available to service our 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, we may experience a material adverse impact on our results of operations and our liquidity.

The profitability of ETP’s midstream and intrastate transportation and storage operations are, 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 processing fee agreements, we process the gas for a fee. If recoveries are less than those guaranteed the producer, we 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, 2008, the NYMEX settlement price for the prompt month contract ranged from a high of $13.11 per MMBtu to a low of $6.47 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, 2008 ranged from a high of approximately $1.96 per gallon to a low of approximately $0.66 per gallon.

 

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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 and NGLs, which factors may result in decisions by natural gas producers to reduce production of natural gas during periods of lower prices for natural gas and NGLs or may result in decisions by end-users of natural gas and NGLs 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:

 

 

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

 

 

the level of domestic oil and natural gas production;

 

 

the availability of imported oil and natural gas;

 

 

actions taken by foreign oil and gas producing nations;

 

 

the availability of local, intrastate and interstate transportation systems;

 

 

the price, availability and marketing of competitive fuels;

 

 

the demand for electricity;

 

 

the impact of energy conservation efforts; and

 

 

the extent of governmental regulation and taxation.

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

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. 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.

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

 

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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. Natural gas prices have been high in recent years compared to historical periods, but have decreased significantly during the fourth quarter of 2008 and thus far in 2009. This decline in natural gas prices coupled with the effect of illiquid capital markets has led to a decrease in drilling activity in some of our areas of operation.

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 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. As the reserves available through the supply basins connected to Transwestern’s systems naturally 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. Investments by third parties in the development of new natural gas reserves connected to Transwestern’s facilities depend on many factors beyond Transwestern’s control.

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.

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. ETP cannot assure you that its 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.

 

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

 

 

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

 

 

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

 

 

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:

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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

If ETP consummates future acquisitions, its capitalization and results of operations may change significantly. As ETP determines the application of its funds and other resources, you 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:

 

 

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

 

 

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

 

 

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

 

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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 or at all or at the budgeted cost. ETP currently has several major expansion and new build projects planned or underway, including the Texas Independence pipeline, the Midcontinent Express pipeline, 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 particular projects. 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 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, 2008, XTO Energy Inc., EnCana Oil and Gas (USA), Inc., Sandridge Energy Inc., and ConocoPhillips Company supplied ETP with approximately 75% of the Southeast Texas System’s natural gas supply. For ETP’s year ended December 31, 2008, XTO Energy Inc., Chesapeake Energy Marketing, Inc., EnCana Oil and Gas (USA), Inc. and EOG Resources, Inc. supplied ETP with approximately 75% 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 Energy, Inc. (“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 ETP’s ET Fuel System. ETP also has an eight-year fee-based transportation contract with TXU Portfolio Management Company, L.P., a subsidiary of TXU Corp., which is referred to as 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 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 our 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 three to eight years. The failure of these 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.

With respect to ETP’s interstate transportation operations, MEP has secured predominantly 10-year firm transportation contracts from a small number of major shippers for all of the initial 1.5 Bcf/d of capacity on the Midcontinent Express pipeline. MEP has also secured firm transportation commitments for an additional 0.3 Bcf/d of capacity on the Midcontinent Express pipeline, which expansion is subject to regulatory approval. FEP has secured a binding 10-year commitment for approximately 1.85 Bcf/d of firm transportation service on the 2.0 Bcf/d Fayetteville Express pipeline project. In connection with ETP’s 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 of the total initial capacity of at least 1.25 Bcf/d. The failure of these key shippers to fulfill their

 

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contractual obligations could have a material adverse effect on ETP’s and our cash flow and results of operations if ETP were 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 Natural Gas Policy Act, or 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 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, failure to comply with the rates approved by FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in an alteration of jurisdictional status and/or the imposition of administrative, civil and criminal penalties.

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 Texas Railroad Commission, or 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 rights as an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and some of the states in which ETP 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 TRCC-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.

 

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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 just and reasonable by FERC. The rates charged by natural gas companies are generally required to be on file with FERC in FERC-approved tariffs. Pursuant to the NGA, existing tariff rates may be challenged by complaint and rate increases proposed by the natural gas company may be challenged by protest. ETP also may be limited by the terms of negotiated rate agreements from seeking future rate increases, or constrained by competitive factors from charging its FERC-approved maximum just and reasonable rates. Further, rates must, for the most part, be cost-based and FERC may, on a prospective basis, order refunds of amounts collected under rates that have been found by FERC to be in excess of a just and reasonable level.

Transwestern filed a general rate case 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) may challenge the lawfulness of tariff rates that have become final and effective. FERC may also investigate such rates absent shipper complaint.

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 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. The certificate order authorizing construction, ownership and operation of Midcontinent Express pipeline is subject to pending requests for clarification and rehearing, and ETP cannot guarantee that this order will not be altered on rehearing or that judicial review, if any, will not result in any change to FERC’s Midcontinent Express pipeline certificate order on remand.

Any successful complaint or protest against the rates of ETP’s interstate natural gas companies could reduce its revenues associated with providing transportation services on a prospective basis. We and ETP cannot assure you 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 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 FERC and the courts for a number of years. It is currently FERC’s policy to permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential income tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. Under the FERC’s policy, ETP 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 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.

 

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

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

 

 

operating terms and conditions of service;

 

 

the types of services interstate pipelines may offer their customers;

 

 

construction of new facilities;

 

 

acquisition, extension or abandonment of services or facilities;

 

 

reporting and information posting requirements;

 

 

accounts and records; and

 

 

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

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

ETP must on occasion rely upon rulings by FERC or other governmental authorities to carry out certain of its business plans. For example, in order to carry out its plan to construct the Fayetteville Express pipeline ETP must, among other things, file and support before FERC an NGA Section 7(c) application for a certificate of public convenience and necessity to build, own and operate such a facility. We and ETP cannot guarantee that FERC will authorize construction and operation of this facility. Moreover, there is no guarantee that, if granted, such certificate authority 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 FERC has granted ETP such certificate authority, there are pending requests for clarification and rehearing of that order. We and ETP cannot guarantee that FERC will, on rehearing, reaffirm in all materials respects its July 25, 2008 Midcontinent Express certificate order. Nor can we or ETP guarantee that FERC’s certificate order will not be subject to judicial review and, ultimately, to possible material alteration if remanded to FERC.

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

Finally, we 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 the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. The total accrued future estimated cost of remediation activities relating to ETP’s Transwestern pipeline operations is approximately $9.1 million, which activities are expected to continue through 2018.

 

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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, which will require 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. 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, President Obama has expressed support for, and it is anticipated that the current session of Congress will consider, legislation to restrict or regulate emissions of greenhouse gases. In addition, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas “cap and trade” programs. These “cap and trade” programs could require major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries or gas processing plants, to acquire emission allowances from other businesses that emit greenhouse gases at levels lower than the limits specified in those programs and then surrender these allowances as a credit against such emissions. Depending on the particular program, ETP could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from ETP’s operations (e.g., compressor stations) or from the combustion of fuels (e.g., natural gas) that ETP processes.

Also, as a result of the United States Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may regulate greenhouse gas emissions from mobile sources such as cars and trucks even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases including carbon dioxide fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources. In July 2008, EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act, in response to the Supreme Court’s decision in Massachusetts. In the notice, EPA evaluated the potential regulation of greenhouse gases under the Clean Air Act and other potential methods of regulating greenhouse gases. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such new federal, regional or state restrictions on emissions of carbon dioxide or other greenhouse gases that may be imposed in areas in which we conduct business could also have an adverse affect on our cost of doing business and demand for the natural gas ETP processes and transports.

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 encounters 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.

 

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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.

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, that may have greater financial resources and access to larger natural gas supplies than ETP does.

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

 

 

price,

 

 

reliability and quality of service,

 

 

responsiveness to customer needs,

 

 

safety concerns,

 

 

long-standing customer relationships,

 

 

the inconvenience of switching tanks and suppliers, and

 

 

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 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.

 

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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, 2008, approximately 27.3% of its sales of natural gas were 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 depends 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 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 regulations relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” 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 for its existing transportation assets other than the Transwestern pipeline will result in capital costs of $27.1 million over the course of the next year, as well as operating and maintenance costs of $27.6 million during that period. During this same time period, ETP estimates that it will incur pipeline integrity costs of $8.9 million, as well as operating and maintenance cost of $1.7 million, with respect to its Transwestern pipeline. Through December 31, 2008, Transwestern did not incur any costs associated with the IMP Rule and has satisfied all of the requirements until 2009. Through December 31, 2008, a total of $16.4 million of capital costs and $12.7 million of operating and maintenance costs have been incurred for pipeline integrity testing for transportation assets other than Transwestern. Through December 31, 2008, a total of $6.9 million of capital costs and $0.4 million of operating and maintenance costs have been incurred for pipeline integrity costs for Transwestern. 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.

 

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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.

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.

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.

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.

 

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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 2008, ETP purchased approximately 50.7%, 15.0% and 14.9% of its propane from Enterprise, Targa Liquids 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 substantially all of its propane from Enterprise pursuant to an agreement that expires in 2010. 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.

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.

 

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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 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. 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 recharacterize 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.

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. You should be aware that 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.

 

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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. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our Unitholders.

If the IRS contests the federal income tax positions we 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.

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, in some cases, state and local income taxes on your 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 federal income tax returns and generally pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our Common Units.

 

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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). 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 you.

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.

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.

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.

Our partnership will be considered to have terminated for federal income tax purposes if transfers of units within a twelve month period constitute the sale or exchange of 50% or more of our capital and profit interests. In order to determine whether a sale or

 

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exchange of 50% or more of capital and profits interests has occurred, we review information available to us regarding transactions involving transfers of our units, including reported transfers of units by our affiliates and sales of units pursuant to trading activity in the public markets; however, the information we are able to obtain is generally not sufficient to make a definitive determination, on a current basis, of whether there have been sales and exchanges of 50% or more of our capital and profits interests within the prior twelve month period, and we may not have all of the information necessary to make this determination until several months following the time of the transfers that would cause the 50% threshold to be exceeded.

The sale of our Common Units by Ray C. Davis and Natural Gas Partners VI, L.P. to Enterprise GP Holdings, L.P. on May 7, 2007, together with all other Common Units sold within the prior twelve months, represented a sale or exchange of 50% or more of the total interest in our capital and profits interests and resulted in our termination and immediate reconstitution as a new partnership for federal income tax purposes. Moreover, our termination resulted in a deemed transfer of all of our interests in ETP, causing a termination of ETP’s partnership for federal income tax purposes. These terminations did not affect our classification or the classification of ETP as a partnership for federal income tax purposes or otherwise affect the nature or extent of our “qualifying income” or the “qualifying income” of ETP for federal income tax purposes. The closing of our taxable years resulted in us and ETP both filing two tax returns (and Unitholders receiving two Schedule K-1’s) for one fiscal year. Moreover, these terminations requireed both us and ETP to close our taxable years and make new elections as to various tax matters. In addition, ETP was required to reset the depreciation schedule for its depreciable assets for federal income tax purposes. The resetting of ETP’s depreciation schedule resulted in a deferral of the depreciation deductions allowable in computing the taxable income allocated to the Unitholders of ETP (including Heritage Holdings as the holder of our Class E units) and, consequently, to our Unitholders. However, elections ETP and ETE made with respect to the amortization of certain intangible assets had the effect of reducing the amount of taxable income that would otherwise be allocated to ETE Unitholders.

The net effect of our tax termination and the tax termination of ETP was an allocation for the 2007 year of (i) an increased amount of taxable income as a percentage of the cash distributed to our Unitholders who acquired their units prior to our initial public offering in February 2006 and (ii) a decrease in the amount of taxable income as a percentage of the cash distributed to our Unitholders who purchased their units on or after the date of our initial public offering in February 2006.

You will likely be subject to state and local taxes and return filing requirements in states where you 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 do 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.

ITEM 2. PROPERTIES

Substantially all of our pipelines, which are located in Arizona, New Mexico, Colorado, Utah, Texas and Louisiana, 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.

 

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We operate bulk storage facilities at approximately 440 customer service locations for our propane operations. We own substantially all of these facilities 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 49.3 million gallons of aboveground storage capacity at our various propane plant sites and have leased an aggregate of approximately 19.2 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 one office building in Helena, Montana for the administration of our propane operations. We also own a field office building in Fruita, Colorado and lease office facilities in Houston, Texas, San Antonio, 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, 2008, we utilized approximately 228 transport truck tractors, 274 transport trailers, 19 railroad tank cars, 2,075 bobtails and 3,866 other delivery and service vehicles, all of which we own. As of December 31, 2008, 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. These 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 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 Partnerships, or contemplated to be brought against us or our Operating Partnerships, under the various environmental protection statutes to which they are subject.

 

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

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None. See Note 7 to our consolidated financial statements.

PART II

ITEM 5. MARKET FOR THE 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 New York Stock Exchange 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 New York Stock Exchange 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
     High    Low    Distribution (1)
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
Transition Period 2007         

Four Months Ended December 31, 2007 (2)

   $ 37.35    $ 31.55    $ 0.5500
Fiscal Year 2007         

Fourth Quarter Ended August 31, 2007

   $ 42.95    $ 29.82    $ 0.3900

Third Quarter Ended May 31, 2007

   $ 41.06    $ 33.20    $ 0.3725

Second Quarter Ended February 28, 2007

   $ 33.70    $ 28.80    $ 0.3560

First Quarter Ended November 30, 2006

   $ 29.99    $ 26.04    $ 0.3400

 

(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.
(2) We changed our fiscal year to the calendar year in November 2007. In connection with this change, we have transitioned to making quarterly cash distributions on a calendar quarter basis that are paid within 50 days following the end of each calendar quarter. To facilitate this transition, we did not make a cash distribution for the three-month period ending November 30, 2007, but instead made a cash distribution for the four-month period ending December 31, 2007 that was paid on February 19, 2008.

Description of Units

As of January 31, 2009, there were approximately 21,540 individual Common Unitholders, which includes Common Units held in street name. Common Units represent limited partner interest in the Partnership’s Amended and Restated Agreement of Limited Partnership, as amended to date (the “Partnership Agreement”) that entitle the holders to the rights and privileges specified in the Partnership Agreement.

 

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Common Units. As of December 31, 2008, we had 222,829,956 Common Units outstanding, of which 113,356,021 were held by the public; 39,768,401 were held by affiliates and 69,705,534 were held by our officers and directors. As of such date, the Common Units represent an aggregate 99.69% limited partner interest in us. Our General Partner owns an aggregate 0.31% General Partner interest in us. Our Common Units are registered under the Securities Exchange Act of 1934, as amended and are listed for trading on the New York Stock Exchange (the “NYSE”). Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the limited partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Cash Distribution Policy.”

Cash Distribution Policy

General. The Parent Company will distribute all of its “Available Cash” to its Unitholders and its General Partner within 50 days following the end of each fiscal quarter.

Definition of Available Cash. Available Cash is defined in the Parent Company’s Partnership Agreement and generally means, with respect to any calendar quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner to:

 

 

provide for the proper conduct of its business;

 

 

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

 

 

provide funds for distributions to Unitholders and its General Partner in respect of any one or more of the next four quarters.

The total amount of distributions declared are reflected in Note 7 to our consolidated financial statements.

Securities Authorized for Issuance Under Equity Incentive Plans

Please see Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters,” of this annual report.

Recent Sales of Unregistered Securities

None.

Issuer Purchases of Equity Securities

None.

ITEM 6. SELECTED FINANCIAL DATA

Currently, the Parent Company has no separate operating activities apart from those conducted by the Operating Partnerships. 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 January 2004, we combined the natural gas midstream and transportation operations of ETC OLP with the retail propane operations of Heritage Propane Partners, L.P. (the “Energy Transfer Transactions”). In March 2004, Heritage changed its name to Energy Transfer Partners, L.P. Although Heritage was the surviving parent entity for legal purposes in the Energy Transfer Transactions, ETC OLP was the acquirer for accounting purposes. As a result, following the Energy Transfer Transactions in January 2004, the historical financial statements of ETC OLP for periods prior to the closing of the Energy Transfer Transactions became our historical financial statements. ETC OLP was formed on October 1, 2002 and has a December 31 year-end. ETC OLP’s predecessor entities had a December 31 year-end.

 

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

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

 

     Year
Ended
December 31,
2008
    Four Months
Ended
December 31,
2007
    Years Ended August 31,  
      
      
       2007     2006     2005     2004  

Statement of Operations Data:

            

Revenues:

            

Midstream segment

   $ 5,342,393     $ 1,166,313     $ 2,853,496     $ 4,223,544     $ 3,246,772     $ 1,880,663  

Intrastate transportation and storage segment

     5,634,604       1,254,401       3,915,932       5,013,224       2,608,108       113,938  

Interstate transportation segment

     244,224       76,000       178,663       —         —         —    

Eliminations

     (3,568,065 )     (664,522 )     (1,562,199 )     (2,359,256 )     (471,255 )     (27,798 )

Retail propane and other retail propane related segment

     1,624,010       511,258       1,284,867       879,556       709,473       349,344  

Other

     16,201       5,892       121,278       102,028       75,700       30,810  
                                                

Total revenues

     9,293,367       2,349,342       6,792,037       7,859,096       6,168,798       2,346,957  

Gross margin

     2,355,287       675,688       1,713,831       1,290,780       787,283       365,533  

Depreciation and amortization

     274,372       75,406       191,383       129,636       105,751       56,242  

Operating income

     1,098,903       316,651       809,336       575,540       297,921       130,806  

Interest expense, net of interest capitalized

     (357,541 )     103,375       279,986       150,646       101,061       41,217  

Gain on Energy Transfer Transactions

     —         —         —         —         —         395,253  

Income from continuing operations before income tax expense and minority interest

     683,562       192,758       563,359       433,907       201,795       484,715  

Income tax expense (a)

     3,808       9,949       11,391       23,015       4,397       2,792  

Minority interests in income from continuing operations

     (304,710 )     (90,132 )     (232,608 )     (303,752 )     (96,946 )     (35,164 )

Income from continuing operations

     375,044       92,677       319,360       107,140       100,452       446,759  

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

     1.68       0.41       1.56       0.80       0.89       4.54  

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

     1.68       0.41       1.55       0.79       0.75       3.35  

Cash distribution per unit

     1.91       0.55       1.46       2.56       2.66       1.36  

Balance Sheet Data (at period end):

            

Current assets

     1,180,995       1,403,796       1,050,578       1,302,736       1,453,730       481,868  

Total assets

     11,069,902       9,462,094       8,183,089       5,924,141       4,905,672       2,865,191  

Current liabilities

     1,208,921       1,241,433       932,815       1,020,787       1,244,785       404,917  

Long-term debt, less current maturities

     7,190,357       5,870,106       5,198,676       3,205,646       2,275,965       1,071,158  

Partners’ capital (deficit)/Stockholders' equity

     (83,432 )     (15,663 )     (47,132 )     45,751       (88,137 )     368,325  

Other Financial Data:

            

Cash flow provided by operating activities

     823,757       147,118       754,497       310,782       38,133       122,098  

Cash flow used in investing activities

     (2,015,585 )     (995,943 )     (2,158,090 )     (1,244,406 )     (1,131,117 )     (731,831 )

Cash flow provided by financing activities

     1,227,294       828,032       1,454,739       926,369       1,043,591       637,513  

Capital expenditures:

            

Maintenance (accrual basis)

     140,968       48,998       89,226       51,826       41,054       22,514  

Growth (accrual basis)

     1,921,679       604,371       998,075       677,861       155,405       87,174  

Acquisition

     84,783       337,092       90,695       586,185       1,131,844       622,929  

 

(a) As a partnership, we are generally not subject to income taxes. However, our subsidiaries, Oasis Pipe Line, Heritage Holdings, Heritage Service Corporation, and Titan Propane Services, Inc. are corporations subject to income taxes.
(b) See Note 4 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 New York Stock Exchange (“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 Partnerships, 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 Partnerships.

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 to our partners 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 amount 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 was 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:

 

 

ET Fuel System in June 2004

 

 

HPL System in January 2005

 

 

Titan Propane in June 2006

 

 

Transwestern in December 2006

 

 

Canyon Gathering System in October 2007

 

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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. Recently, we announced the construction of the Texas Independence pipeline expected to be completed in the third quarter of 2009, as well as the completion of several projects including our Southeast Bossier pipeline in April 2008, and our San Juan Loop, Paris Loop, Maypearl to Malone and Carthage Loop projects in the third quarter of 2008. 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 primarily conducted in the following significant segments:

 

 

Midstream - Revenue is primarily dependent upon the volumes of natural gas gathered, compressed, treated, processed, transported, purchased and sold through our pipelines (excluding the transportation pipelines) and gathering systems as well as the level of natural gas and NGL prices.

 

 

Intrastate transportation and storage - Revenue is typically generated from fees charged to customers to reserve firm capacity on or move gas through the pipeline on an interruptible basis. A monetary fee and/or fuel retention are also components of the fee structure. Excess fuel retained after consumption is typically valued at the first of the month published market prices and strategically sold when market prices are high. The 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. The use of the Bammel storage reservoir allows us to purchase physical natural gas and then sell financial contracts at a price sufficient to cover its carrying costs and provide a gross profit margin.

 

 

Interstate transportation - The revenues of this segment consist primarily of fees earned from natural gas transportation services and operational gas sales.

 

 

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

Summary of Operating Financial Performance in 2008

For the year ended December 31, 2008, our gross margin was $2.36 billion and operating income was $1.10 billion. During 2008, we completed several significant intrastate pipeline projects and we announced several new intrastate and interstate pipeline construction projects. In addition, we experienced increased volumes in our natural gas operations and better than expected processing margins throughout most of the year. We continue to experience significant demand from our customers for transportation capacity through our extensive pipeline network.

ETP’s Operations

Our midstream and propane operations are primarily margin-driven businesses, while our transportation and storage operations are primarily fee-driven businesses. Thus, our results are significantly impacted by the margins we realize and the volumes we sell, transport and store, and to a lesser extent, commodity prices. Our year 2008 results were significantly impacted by the completion of several pipeline projects that were completed during 2007 and 2008.

Despite the slow down in home construction, the economic recession and increased fuel prices that caused customer conservation, our propane operations were able to deliver better than expected results. Historically, as the weather becomes colder, the sales volumes and revenues would typically increase. For the year ended December 31, 2008 the weather was slightly colder than normal, but volume trends did not track as closely to weather pattern trends in 2008 due to the reasons mentioned above. Our retail propane volumes decreased due to continued conservation, but were offset by volumes added through acquisitions. We also were able to increase our sales prices during the first nine months of 2008 which improved our gross margins. Additionally, due to the acquisitions we made during 2008, our other propane segment revenues, such as appliance sales, labor and tank rentals, also improved over prior years.

From a capital resource perspective, ETP continued to secure long-term financing and successfully raised $2.10 billion in long-term debt with interest rates ranging from 6.0% to 9.70% and maturities ranging from 5 to 30 years (subject to the 3-year put option relating to the ETP 9.70% Senior Notes as described below under “- Financing and Sources of Liquidity – Description of Indebtedness”). ETP also received net proceeds of approximately $373.0 million from the sale of its Common Units during the year ended December 31, 2008. These proceeds were used to repay borrowings under the ETP 364-Day Credit Facility (defined below) and a portion of the debt outstanding under ETP’s revolving credit facility (the “ETP Credit Facility”).

On January 27, 2009, ETP closed a public offering of 6,900,000 Common Units representing limited partner interests at $34.05 per Common Unit. ETP used the net proceeds from the offering

 

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to repay approximately $225.9 million outstanding debt under the ETP Credit Facility. ETP expects to use some of the increased availability under the ETP Credit Facility to finance capital expenditures and other growth projects.

Trends and Outlook

The current constraints in the capital markets may affect our ability to obtain funding through new borrowings or the issuance of Common Units. In addition, we expect that, to the extent we are successful in arranging new debt financing, we will incur increased costs associated with these debt financings. In light of the current market conditions, we have taken steps to preserve our liquidity position including, but not limited to, reducing discretionary capital expenditures, maintaining our cash distribution rate and continuing to appropriately manage operating and administrative costs to improve profitability. ETP also successfully completed a $600.0 million senior note offering in December 2008 and a 6.9 million ETP Common Unit offering in January 2009. As of December 31, 2008, in addition to approximately $91.9 million of cash on hand, we had available capacity under the Parent Company’s debt facilities and the ETP Credit Facility of $1.42 billion. On a pro forma basis, as of December 31, 2008, taking into account net proceeds of approximately $225.9 million from ETP’s January 2009 equity offering, available capacity under the ETP Credit Facility was $1.27 billion. We expect to utilize these resources, along with cash from operations, to fund our announced growth capital expenditures for 2009 and working capital needs during 2009. In addition to these sources of liquidity, we may also access the debt and equity markets during 2009 in order to provide additional liquidity to fund growth capital expenditures for future years or for other partnership purposes.

ETP will continue to evaluate a variety of financing sources in order to fund its future growth capital expenditures and working capital needs, including funds available under our existing revolving credit facility, funds raised from future equity and/or debt offerings and funds raised from other sources, which sources may include project financing or other alternative financing arrangements from third parties or affiliated parties. In this regard, ETP has initiated discussions with us regarding the prospect of our purchasing additional ETP Common Units from ETP. We have an aggregate of approximately $378.4 million of cash on hand and available borrowing capacity under our revolving credit facility as of December 31, 2008.

We believe that the size and scope of our operations, our stable asset base and cash flow profile and our investment grade status will be significant positive factors in our efforts to obtain new debt or equity funding; however, there is no assurance that we will be successful in obtaining financing under any of the alternatives discussed above if current capital market conditions continue for an extended period of time or if markets deteriorate further from current conditions. Furthermore, the terms, size and cost of any one of these financing alternatives could be less favorable and could be impacted by the timing and magnitude of our funding requirements, market conditions, and other uncertainties.

Current economic conditions also indicate that many of our customers may encounter increased credit risk in the near term. In particular, 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. 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.

In our intrastate and interstate natural gas operations, a significant portion of our revenue is derived from long-term fee-based arrangements pursuant to which our customers pay us capacity reservation charges regardless of the volume of natural gas transported; however, a portion of our revenue is derived from charges based on actual volumes transported. As a result, our operating cash flows from our natural gas pipeline operations are not tied directly to changes in natural gas and NGL prices; however, the volumes of natural gas we transport may be adversely affected by reduced drilling activity of our customers as a result of lower natural gas prices. As a portion of our pipeline transportation revenue is based on volumes transported, lower volumes of natural gas transported would result in lower revenue from our intrastate and interstate natural gas operations. Based on the significant level of revenue we receive from reservation capacity charges under long-term contracts and our review of the recent announcements of drilling plans by our customers, we do not expect the current level of natural gas prices to have a significant adverse effect on our operating results; however, there are no assurances that commodity prices will not decline further, which could result in a further reduction in drilling activities by our customers.

 

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Since certain of our natural gas marketing operations and substantially all of our propane operations involve the purchase and resale of natural gas and NGLs, we expect our revenues and costs of products sold to be lower than prior periods if commodity prices remain at or fall below existing levels. However, we do not expect our margins from these activities to be significantly impacted as we typically purchase the commodity at a lower price than the sales price. Since the prices of natural gas and NGLs have been volatile, there are no assurances that we will ultimately sell the commodity for a profit.

As noted above, we may reduce our level of discretionary capital expenditures for growth projects in order to preserve our capital resources in the event that the capital market conditions do not allow us to obtain debt or equity financing on reasonable terms. In the event we do not pursue growth projects due to lack of capital, we would likely not achieve the growth in distributable cash flow as we have previously planned.

We actively monitor the credit status of our counterparties, performing both quantitative and qualitative assessments based on their credit ratings and credit default swaps where applicable, and to date have not had any significant credit defaults associated with our transactions. However, given the current volatility in the financial markets, we cannot be certain that we will not experience such losses in the future.

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.

In November 2007, we changed our fiscal year end to the calendar year. Thus, our current 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 twelve months ended December 31, 2008, the four month periods ended December 31, 2007 and 2006 and the fiscal years ended August 31, 2007 and 2006.

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 fiscal 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 year ended December 31, 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 on our HPL system. Since we buy and sell 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 speculative trading activities 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 Partnerships. 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, 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:

 

     Year Ended
December 31,
2008
    Year Ended
August 31,

2007
    Amount of
Change
 

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 under SFAS 133. 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

 

     Year Ended
December 31,
2008
    Year Ended
August 31,
2007
    Amount of
Change
 

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 )

Gain (loss) 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  

Minority interests

     (304,710 )     (232,608 )     (72,102 )
                        

Net income

   $ 375,044     $ 319,360     $ 55,684  
                        

See the detailed discussion of revenues, cost of products sold, gross margin and operating expense 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 under SFAS 133. Changes in the value of these swaps were recorded directly in earnings. The variable portion of these swaps were 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 (“CIAC”) related to $40.0 million reimbursement in connection with an extension on our Southeast Bossier pipeline (see Note 3 to our consolidated financial statements).

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.

Minority Interests. The increase in minority interest expense is attributable to the increase in income from continuing operations of ETP described below that is allocated to the minority unitholders of our subsidiaries. The minority interest expense primarily represents limited partnership interests in ETP that we do not own.

 

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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.

We do not include earnings from equity method unconsolidated affiliates in our measurement of operating income because such earnings have not been significant historically.

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

Operating income by segment is as follows:

 

     Year Ended
December 31,
2008
    Year Ended
August 31,
2007
    Amount of
Change
 

Midstream

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

Intrastate Transportation and Storage

     710,070       479,820       230,250  

Interstate Transportation

     124,676       95,650       29,026  

Retail Propane

     114,564       124,263       (9,699 )

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  
                        

We do not believe the Other operating income is material for further disclosure and/or discussion.

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 Partnerships 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.

Midstream

 

     Year Ended
December 31,
2008
   Year Ended
August 31,
2007
   Amount of
Change

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
                    

 

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

 

 

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;

 

 

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

 

 

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.

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. Effective January 1, 2008, we began allocating legal costs related to regulatory matters among the midstream and transportation and storage segments. During the year ended August 31, 2007, all legal costs related to regulatory matters were recorded in the midstream segment.

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.

Intrastate Transportation and Storage

 

     Year Ended
December 31,
2008
   Year Ended
August 31,
2007
   Amount of
Change
 

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  
                      

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

 

 

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;

 

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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,

 

 

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 $68.2 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 primarily due to an increase of $15.7 million in allocated legal fees and an increase in other allocated costs of $8.3 million. Effective January 1, 2008, we began allocating legal costs related to regulatory matters equally between the midstream and transportation and storage segments. During the year ended August 31, 2007, all legal costs related to regulatory matters were recorded in the midstream segment.

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.

Interstate Transportation

 

     Year Ended
December 31,
2008
   Year Ended
August 31,
2007
   Amount of
Change
 

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.

 

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Retail Propane

 

     Year Ended
December 31,
2008
   Year Ended
August 31,
2007
   Amount of
Change
 

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.

Revenues. Retail propane revenues increased 28.5% or $335.5 million in the year ended December 31, 2008 as compared to the year ended August 31, 2007. The retail propane revenue variance between these periods was principally impacted by the increase in propane selling prices in the later period presented to keep pace with the increases in the wholesale price of propane. 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.

Cost of Products Sold. Retail propane cost of products sold increased significantly due to the increase in the average fuel price purchased for resale during 2008. While 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 commitments, we utilize financial instruments (swap agreements) as purchase commitments to lock in the 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.

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. The 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 primarily due to the aforementioned, offset by the accounting impact of the unrealized losses recorded on financial instruments as noted above.

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.

 

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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,
   Amount of
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 )

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).

 

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Consolidated Results

 

     Four Months Ended
December 31,
    Amount of
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 )

Gain (loss) 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 )

Minority interests

     (90,132 )     (50,204 )     (39,928 )
                        

Net income

   $ 92,677     $ 76,681     $ 15,996  
                        

See the detailed discussion of revenues, cost of products sold, margin and operating expense 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 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.

Minority Interests. The increase in minority interest expense in the four months ended December 31, 2007 is attributable to the increase in income from continuing operations of ETP described below that is allocated to the minority unitholders of our subsidiaries. The minority interest expense primarily represents limited partnership interests in ETP that we do not own.

 

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Segment Operating Results

Operating income by segment is as follows:

 

     Four Months Ended
December 31,
    Amount of
Change
 
     2007     2006    

Midstream

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

Intrastate Transportation and Storage

     169,361       109,262       60,099  

Interstate Transportation

     29,657       11,854       17,803  

Retail Propane

     46,747       49,841       (3,094 )

Other

     (796 )     528       (1,324 )

Unallocated selling, general and administrative expenses

     (171 )     (9,090 )     8,919  
                        

Operating income

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

We do not believe the Other operating income is material for further disclosure or discussion.

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 Partnerships 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 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 Partnerships exceeded total incurred costs.

Midstream

 

     Four Months Ended
December 31,
   Amount of
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:

 

 

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;

 

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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;

 

 

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

 

 

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.

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.

Intrastate Transportation and Storage

 

     Four Months Ended
December 31,
   Amount of
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:

 

 

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.

 

 

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.

 

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

 

 

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

 

 

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.

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,
   Amount of
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.

 

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Retail Propane

 

     Four Months Ended
December 31,
   Amount of
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.

Revenues. Retail propane revenues increased $61.7 million mainly due to increased sale prices driven by the 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.

Cost of Products Sold. Retail propane cost of products sold increased by $58.7 million 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.

Gross Margin. Overall gross margins increased $3.6 million even though gallon sales decreased. The propane margin remained strong despite warmer weather conditions and higher fuel prices. 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.

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 partnerships, 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.

Fiscal Year Ended August 31, 2007 compared to Fiscal Year Ended August 31, 2006 (tabular dollar amounts in thousands)

 

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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 August 31,     Amount of
Change
 
     2007     2006    

Equity in earnings of affiliates

   $ 435,247     $ 204,987     $ 230,260  

Selling, general and administrative expenses

     8,496       55,374       (46,878 )

Interest expense

     104,405       36,773       67,632  

Loss on extinguishment of debt

     —         5,060       (5,060 )

Losses on non-hedged interest rate derivatives

     (1,952 )     —         (1,952 )

Other, net

     (405 )     (638 )     233  

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 Class A and Class B limited partner interests of ETP GP and its investment in ETP LLC. The increase in equity in earnings of affiliates for the year ended August 31, 2007 compared to the year ended August 31, 2006 was directly related to the increased ownership in ETP as a result of the Common, Class F and Class G Unit acquisitions in February 2006 and November 2006 and the increased ownership of ETP IDRs, as discussed above, and the changes in the ETP segment income described below.

The change in the Parent Company’s ownership share of ETP during fiscal years 2007 and 2006 was as follows:

 

     Limited
Partner
Interest
    IDRs     General
Partner
Interest
 

Interest as of December 2005

   31 %   50 %   2 %

Purchase of ETP Common and Class F

      

Units in February 2006

   2 %   —       —    

Purchase of ETP Class G Units in November 2006

   13 %   —       —    

Purchase of IDRs from ETI in November 2006

   —       50 %   —    
                  

interests as of August 31, 2007

   46 %   100 %   2 %
                  

General and Administrative Expenses. The decrease in general and administrative expenses of the Parent Company for the year ended August 31, 2007 compared to the year ended August 31, 2006 and the increase in general and administrative expenses for the year ended August 31, 2006 compared to the year ended August 31, 2005 is primarily due to the compensation expense of $52.9 million recorded in fiscal year 2006 in connection with the issuance of Class B Units by the Parent Company in conjunction with its IPO. (See Note 7 to our consolidated financial statements).

Interest Expense. The Parent Company interest expense increased for the year ended August 31, 2007 compared to 2006 primarily due to the increased borrowings to fund the acquisition of Class G units from ETP in November 2006. Please read “Description of Indebtedness” under “Liquidity and Capital Resources” and Note 6 to our consolidated financial statements for more information on the Parent Company’s indebtedness.

Loss on Extinguishment of Debt. The Parent Company expensed $5.1 million in deferred financing costs during fiscal year 2006 in connection with the repayment of the $600.0 million senior secured term loan agreement as described above. There was no similar repayment during fiscal year 2007.

 

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Consolidated Results

 

     Years Ended August 31,     Amount of
Change
 
     2007     2006    

Revenues

   $ 6,792,037     $ 7,859,096     $ (1,067,059 )

Cost of products sold

     5,078,206       6,568,316       (1,490,110 )
                        

Gross margin

     1,713,831       1,290,780       423,051  

Operating expenses

     559,600       422,989       136,611  

Depreciation and amortization

     191,383       129,636       61,747  

Selling, general and administrative

     153,512       162,615       (9,103 )
                        

Operating income

     809,336       575,540       233,796  

Interest expense, net of interest capitalized

     (279,986 )     (150,646 )     (129,340 )

Loss on extinguishment of debt

     —         (5,060 )     5,060  

Equity in earnings (losses) of affiliates

     5,161       (479 )     5,640  

Gain (loss) on disposal of assets

     (6,310 )     851       (7,161 )

Other, net

     35,158       13,701       21,457  

Income tax expense

     (11,391 )     (23,015 )     11,624  

Minority interests

     (232,608 )     (303,752 )     71,144  
                        

Net income

   $ 319,360     $ 107,140     $ 212,220  
                        

See the detailed discussion of revenues, cost of products sold, gross margin and operating expense by operating segment below.

Interest Expense. Interest expense increased between the comparable periods principally due to a net $67.6 million increase in interest expense related to borrowings of the Parent Company, a net $51.2 million increase in interest expense related to borrowings from ETP’s offerings of Senior Notes and the ETP Credit Facility. Borrowings increased primarily due to the financing of our growth capital expenditures and the CCEH/Transwestern and Titan acquisitions. Debt assumed in the Transwestern acquisition resulted in $12.5 million of increased interest expense. During the year ended August 31, 2006 losses of $0.1 million on interest rate swaps were recorded as an increase to interest expense. Such activity was not recognized in interest expense in the year ended August 31, 2007; rather, such activity was included in interest and other income. Hedge ineffectiveness charges increased interest expense by $1.8 million in fiscal 2007, compared to gains of $0.8 million in fiscal 2006. See Note 12—“Price Risk Management Assets and Liabilities”, included in our consolidated financial statements for further discussion on interest rate hedges. Propane related interest decreased $5.1 million due primarily to the scheduled debt payments that have occurred between fiscal periods 2006 and 2007.

Loss on Extinguishment of Debt. The loss on extinguishment of debt during fiscal year 2006 is discussed above under “Parent Company Only Results.”

Equity in Earnings of Affiliates. The increase in equity in earnings of affiliates between the comparable periods was due primarily to $5.1 million of equity income from our 50% ownership of CCEH for the month of November 2006. We did not have an investment in CCEH in fiscal 2006. We redeemed our investment in CCEH in connection with our Transwestern acquisition on December 1, 2006.

Gain (Loss) on Disposal of Assets. The loss on disposal of assets reflected in the year ended August 31, 2007 resulted from the sale of a compressor station.

Other, Net. The increase in interest and other income between the comparable periods is due primarily to gains on interest rate swaps that are not accounted for as cash flow hedges. Such gains were included in interest expense in fiscal 2006. Other income in fiscal year 2006 includes $7.7 million received from the favorable judgment on the SCANA litigation (see Note 7 of our consolidated financial statements for further detail).

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

 

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The decreased expense for the year ended August 31, 2007 was attributed principally to higher income from trading gains recognized by a taxable subsidiary during the year ended August 31, 2006, than was realized by such subsidiary in 2007. The decrease was partially offset by the Texas margin tax that was not effective until January 1, 2007.

Minority Interest Expense from Continuing Operations. The decrease in minority interest expense in fiscal year 2007 is attributable to the Parent Company’s acquisition of ETP limited partner interests in November 2006 (discussed above), offset by the increase in income from continuing operations of ETP described below that is allocated to the minority unitholders of our subsidiaries. The minority interest expense primarily represents partnership interests in ETP that we do not own.

The increase in minority interest expense in fiscal year 2006 is attributable to the increase in income from continuing operations of ETP described below that is allocated to the minority unitholders of our subsidiaries. The minority interest expense primarily represents partnership interests in ETP that we do not own.

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.

We do not include earnings from equity method unconsolidated affiliates in our measurement of operating income because such earnings have not been significant historically.

For additional information regarding our business segments, see Item 1 and Notes 1 and 15 to our Consolidated Financial Statements included under Item 8 of this annual report.

Operating income by segment is as follows:

 

     Years Ended August 31,     Amount of
Change
 
     2007     2006    

Midstream

   $ 119,233     $ 147,564     $ (28,331 )

Intrastate Transportation and Storage

     479,820       422,420       57,400  

Interstate Transportation

     95,650       —         95,650  

Retail Propane

     124,263       76,055       48,208  

Other

     1,735       1,899       (164 )

Unallocated selling, general and administrative expenses

     (11,365 )     (72,398 )     61,033  
                        

Operating income

   $ 809,336     $ 575,540     $ 233,796  
                        

We do not believe the Other operating income is material for further disclosure and/or discussion.

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 to the Operating Partnerships. For the year ended August 31, 2007, a net $18.4 million was allocated to the Operating Partnerships, which constituted the decrease in total unallocated selling general and administrative expenses from the year ended August 31, 2006. The decrease in the unallocated selling, general and administrative expenses due to the allocations now in place to the Operating Partnerships is offset by increases in expenses primarily related to management incentive plans.

 

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Midstream

 

     Years Ended August 31,    Amount of
Change
 
     2007    2006   

Natural gas MMBtu/d - sold

     941,140      1,552,753      (611,613 )

NGLs Bbls/d - sold

     25,657      10,425      15,232  

Revenues

   $ 2,853,496    $ 4,223,544    $ (1,370,048 )

Cost of products sold

     2,632,187      4,000,461      (1,368,274 )
                      

Gross margin

     221,309      223,083      (1,774 )

Operating expenses

     39,148      31,910      7,238  

Depreciation and amortization

     27,331      19,687      7,644  

Selling, general and administrative

     35,597      23,922      11,675  
                      

Segment operating income

   $ 119,233    $ 147,564    $ (28,331 )
                      

Volumes. The decrease in natural gas volumes sold was principally due to less favorable market conditions during fiscal 2007 and increased utilization of capacity on our transportation pipelines by third parties resulting in lower sales volumes conducted by our marketing operations. The increase in NGL sales volumes was principally due to the completion of our Godley plant during 2007 and favorable market conditions to process and extract NGLs during fiscal 2007 compared to the same period last year.

Gross Margin. Midstream’s gross margin decreased by $1.8 million primarily due to the net effect of the following factors:

 

 

Decrease in net trading revenues of $17.9 million. During the fiscal 2006 period, we recognized trading gains resulting principally from commodities futures positions that benefited from market anomalies following the hurricanes that struck the Texas and Louisiana coasts in August and September 2005. Trading activities during the year ended August 31, 2007 resulted in a net gain of $2.2 million;

 

 

Decrease in non-trading margin from our marketing activities of $36.0 million. Market conditions, including lower basis differentials between the west and east Texas markets and increased third-party utilization of our transportation pipeline capacity, resulted in lower sales volumes conducted by our marketing operations; and

 

 

Increase in processing margin and fee-based revenue. The increase was due to the completion of our Godley plant in the first quarter of 2007, the acquisition of three gathering systems during fiscal 2007, and favorable processing conditions during fiscal 2007 compared to the same period last year at our Southeast Texas System.

Operating Expenses. The increase in midstream operating expenses was primarily driven by increased compressor rental expense of $3.7 million, increased compressor maintenance of $1.0 million, increased electricity costs of $0.9 million, and increased employee-related costs, such as salaries, incentive compensation and healthcare costs, of $1.8 million. The increases were primarily driven by the Godley plant addition and the acquisition of three gathering systems during the first six months of fiscal 2007. The increases were offset by reduced measurement expense of $1.6 million due to a larger portion being allocated to the transportation segment due to the continued expansion in that segment.

Selling, General and Administrative Expenses. The midstream general and administrative expenses increase was primarily due to a $13.2 million increase in legal costs primarily associated with regulatory inquiries, a $4.1 million allocation of parent company administrative expenses for overhead costs which previously had not been allocated, and increases of $3.9 million in employee-related costs such as salaries, incentive compensation and healthcare costs. The increase was offset by increases of $7.9 million in departmental costs allocated to the intrastate transportation and storage operating segment and an increase of $2.4 million in overhead costs capitalized to capital expansion projects.

Depreciation and Amortization. Midstream depreciation and amortization expense increased during the comparable periods primarily due to plant and equipment placed into service during fiscal year 2007, the completion of our Godley plant in the first fiscal quarter of 2007, and the acquisitions of three gathering systems in the first and second fiscal quarters of 2007.

 

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Intrastate Transportation and Storage

 

     Years Ended August 31,    Amount of
Change
 
     2007    2006   

Natural gas MMBtu/d - transported

     6,124,423      4,633,069      1,491,354  

Natural gas MMBtu/d - sold

     1,400,753      1,580,638      (179,885 )

Revenues

   $ 3,915,932    $ 5,013,224    $ (1,097,292 )

Cost of products sold

     3,137,712      4,322,217      (1,184,505 )
                      

Gross margin

     778,220      691,007      87,213  

Operating expenses

     181,133      171,312      9,821  

Depreciation and amortization

     64,423      50,755      13,668  

Selling, general and administrative

     52,844      46,520      6,324  
                      

Segment operating income

   $ 479,820    $ 422,420    $ 57,400  
                      

Volumes and Gross Margin. Intrastate transportation and storage gross margin increased between the comparable periods by $87.2 million principally due to the net effect of the following:

 

 

Overall volumes on our transportation pipelines were higher during fiscal 2007 compared to fiscal 2006 due to the completion of the Cleburne to Carthage pipeline, continued efforts to secure long-term shipper contracts, increased demand to transport natural gas from the Barnett Shale and Bossier Sands producing regions, and a colder winter in fiscal 2007. Natural gas sales volumes on the HPL System for the year ended August 31, 2007 decreased principally due to less volumes sold to east Texas markets as a result of lower price differentials and 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. As such, we now account for these activities as natural gas transported rather than natural gas sold.

 

 

Transportation fees increased approximately $61.0 million for the year ended August 31, 2007 compared to the year ended August 31, 2006. Retention revenue increased approximately $35.1 million due to increased volumes transported on our pipelines;

 

 

Lower natural gas prices. Excluding the impact of volumetric changes, our fuel retention fees are directly impacted by changes in natural gas prices. Increases in natural gas prices tend to increase our fuel retention fees and decreases in natural gas prices tend to decrease our fuel retention fees. Our average natural gas prices for retained fuel decreased from a range of $5.00 to $12.00/MMBtu during the year ended August 31, 2006 to $4.00 to $7.00/MMBtu during the same period this year resulting in a decrease in revenue by $28.8 million;

 

 

Increase in storage margin of $26.0 million. The increase was due to approximately $40.0 million in margin recognized on 17.5 Bcf more volume withdrawn from our Bammel storage facility in fiscal 2007 than in fiscal 2006 and a significant loss on settled derivatives during fiscal 2006. These increases were offset by approximately $18.0 million in margin on gas sold from our Bammel storage facility and delivered to a customer in September 2005. There were no similar sales during the year ended August 31, 2007; and

 

 

Decrease in margin of $28.7 million related to well head volumes. As discussed above, we purchase natural gas from producers at a discount to a specified price and resell to customers at an index price. We experienced lower volumes and lower natural gas prices during the year ended August 31, 2007 compared to the same period last year.

Operating Expenses. Intrastate transportation and storage operating expenses increased between comparable periods primarily due to increases of $12.5 million in pipeline and compressor maintenance and compressor rentals, $3.6 million in property taxes, and $2.3 million in employee-related costs such as salaries, incentive compensation and healthcare costs. These increases were offset by a decrease of $11.0 million in fuel consumption which was due to higher natural gas prices in the early part of fiscal 2006.

Selling, General and Administrative Expenses. Intrastate transportation and storage general and administrative expenses increased between comparable periods primarily due to an increase in certain departmental costs allocated from the midstream segment. The increase in allocated departmental costs is primarily due to the significance of the operations added to the intrastate transportation segment from the various construction projects.

 

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Depreciation and Amortization. Intrastate transportation and storage depreciation and amortization expense increased between comparable periods primarily due to plant and equipment placed into service during fiscal year 2007.

Interstate Transportation

 

     Years Ended August 31,    Amount of
Change
     2007    2006   

Natural gas MMBtu/d - transported

     1,802,109      —        1,802,109

Natural gas MMBtu/d - sold

     19,680      —        19,680

Revenues

   $ 178,663    $ —      $ 178,663

Operating expenses

     36,295      —        36,295

Depreciation and amortization

     27,972      —        27,972

Selling, general and administrative

     18,746      —        18,746
                    

Segment operating income

   $ 95,650    $ —      $ 95,650
                    

The increase in all categories between fiscal years ended August 31, 2007 and 2006 was attributable to the Transwestern acquisition on December 1, 2006.

Retail Propane

 

     Years Ended August 31,    Amount of
Change
     2007    2006   

Retail propane gallons sold (in thousands)

     604,269      429,118      175,151

Retail propane revenues

   $ 1,179,073    $ 799,358    $ 379,715

Other retail propane related revenues

     105,794      80,198      25,596

Retail propane cost of products sold

     734,204      493,642      240,562

Other retail propane related cost of products sold

     25,430      21,776      3,654
                    

Gross margin

     525,233      364,138      161,095

Operating expenses

     297,469      212,188      85,281

Depreciation and amortization

     70,833      58,036      12,797

Selling, general and administrative

     32,668      17,859      14,809
                    

Segment operating income

   $ 124,263    $ 76,055    $ 48,208
                    

Volumes. The retail propane operations realized significant increases (a 175.2 million net gallon increase) in gallons sold between comparable periods primarily due to the Titan acquisition in June 2006. The combination of below normal degree days, customer conservation, and the slow down of new home construction in our propane markets has contributed to a decrease in expected volumes sold and slowed internal growth. The overall weather in our areas of operations during the year ended August 31, 2007 was 10.6% warmer than the year ended August 31, 2006 and 7.2% warmer than normal.

Revenues. Retail propane revenue increased between comparable periods, mainly due to the increase in volumes sold by customer service locations added through the Titan acquisition in June 2006. The increase in retail propane revenues was offset somewhat by weather that was 7.2% warmer than normal weather and 10.6% warmer than last year. Other retail propane related revenues increased $25.6 million for the year ended August 31, 2007 compared to fiscal year 2006 primarily due to other propane related revenues of companies we have acquired between the two years and enhanced fee generating programs in servicing our customers.

Cost of Products Sold. Retail propane cost of products sold increased between comparable periods mainly due to the increase in gallons sold by customer service locations added through the Titan acquisition.

Gross Margin. The overall increase in gross margin between comparable periods is primarily related to the Titan acquisition in June 2006. The propane margin remained strong during the fiscal year ended August 31, 2007 during the periods of warmer weather and higher fuel prices. Our margin is influenced by market opportunities, independent competitors and concerns for long term retention of customers.

 

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Operating Expenses. The increase in operating expenses between comparable periods is directly related to the operating expenses of the identifiable Titan operations. Included in these operating expenses are increases that relate to higher vehicle fuel costs and other vehicle expenses, and general increases in other operating expenses including safety training costs of the newly acquired employees from the Titan acquisition, and other acquisition costs related to blends and mergers of propane locations to gain forward synergies and cost savings.

Selling, General and Administrative Expenses. The increase in selling, general and administrative expenses between comparable periods is primarily due to increases from administrative expense allocations, increases in administrative bonuses, salaries and deferred compensation expense related to increases in staffing and additional restricted unit awards outstanding and the addition of administrative employees from the Titan acquisition. The increase also includes increases in our information technology costs as we continue to enhance our current infrastructure for our administrative and propane systems. Effective with the Transwestern acquisition in December 2006, an allocation of administrative expenses is now made to the operating partnerships, which increased the retail propane selling, general and administrative expenses by a net $7.9 million for the year ended August 31, 2007.

Depreciation and Amortization Expense. The increase in depreciation and amortization expense between comparable periods is due primarily to the acquisition of Titan on June 1, 2006.

Income Taxes

As a limited partnership we generally are not subject to income tax. We are, however, subject to a statutory requirement that our non-qualifying income (including income such as derivative gains from trading activities, service income, tank rentals and others) cannot exceed 10% of our total gross income, determined on a calendar year basis under the applicable income tax provisions. If the amount of our non-qualifying income exceeds this statutory limit, we would be taxed as a corporation. Accordingly, certain activities that generate non-qualified income are conducted through taxable corporate subsidiaries (“C corporations”). These C corporations are subject to federal and state income tax and pay the income taxes related to the results of their operations. For the years ended December 31, 2008, and August 31, 2007 and 2006, and the four months ended December 31, 2007, our non-qualifying income did not exceed the statutory limit.

Our partnership will be considered to have terminated for federal income tax purposes if transfers of units within a 12-month period constitute the sale or exchange of 50% or more of our capital and profit interests. In order to determine whether a sale or exchange of 50% or more of capital and profits interests has occurred, we review information available to us regarding transactions involving transfers of our units, including reported transfers of units by our affiliates and sales of units pursuant to trading activity in the public markets; however, the information we are able to obtain is generally not sufficient to make a definitive determination, on a current basis, of whether there have been sales and exchanges of 50% or more of our capital and profits interests within the prior 12-month period, and we may not have all of the information necessary to make this determination until several months following the time of the transfers that would cause the 50% threshold to be exceeded.

We exceeded the 50% threshold on May 7, 2007, and, as a result, our partnership terminated for federal tax income purposes on that date. Our termination also caused ETP to terminate for federal income tax purposes on that date. These terminations did not affect our classification or the classification of ETP as a partnership for federal income tax purposes or otherwise affect the nature or extent of our “qualifying income” or the “qualifying income” of ETP for federal income tax purposes. These terminations required both us and ETP to close our taxable years and to make new elections as to various tax matters. In addition, ETP was required to reset the depreciation schedule for its depreciable assets for federal income tax purposes. The resetting of ETP’s depreciation schedule resulted in a deferral of the depreciation deductions allowable in computing the taxable income allocated to the Unitholders of ETP and, consequently, to our Unitholders. However, elections ETP and ETE made with respect to the amortization of certain intangible assets had the effect of reducing the amount of taxable income that would otherwise be allocated to ETE Unitholders.

As a result of the tax termination discussed above, we elected new depreciation and amortization policies for income tax purposes, which include the amortization of goodwill. As a result of the income tax regulations related to remedial income allocations, ETP’s wholly-owned subsidiary, HHI, which owns ETP’s Class E units, receives a special allocation of taxable income, for income tax purposes only, essentially equal to the amount of goodwill amortization deductions allocated to purchasers of ETP Common Units.

 

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The amount of such “goodwill” accumulated as of the date of ETP’s acquisition of HHI (approximately $158 million) is now being amortized over 15 years beginning on May 7, 2007, the date of our new tax elections. ETP accounts for HHI using the treasury stock method due to its ownership of ETP’s Class E units. Due to the accounting rules outlined in SFAS 109 and related Interpretations, ETP accounts for the tax effects of the goodwill amortization and remedial income allocation as an adjustment of ETP’s HHI purchase price allocation, which effectively results in a charge to ETP’s common equity and a deferred tax benefit offsetting the current tax expense resulting from the remedial income allocation for tax purposes. For the year ended December 31, 2008, this resulted in a current tax expense and deferred tax benefit (with a corresponding charge to common equity as an adjustment of the purchase price allocation) of approximately $3.4 million. As of December 31, 2008, the amount of tax goodwill to be amortized over the next 14 years for which HHI will receive a remedial income allocation is approximately $143.0 million.

The difference between the statutory rate and the effective rate is summarized as follows:

 

     Year
Ended
December 31,

2008
    Four Months
Ended
December 31,

2007
   

 

Years Ended August 31,

 
       2007     2006  

Federal statutory tax rate

   35.00 %   35.00 %   35.00 %   35.00 %

State income tax rate net of federal benefit

   1.59 %   2.57 %   1.25 %   3.10 %

Earnings not subject to tax at the Partnership level

   (36.03 )%   (32.41 )%   (34.23 )%   (32.80 )%
                        

Effective tax rate

   0.56 %   5.16 %   2.02 %   5.30 %
                        

Income tax expense consists of the following current and deferred amounts:

 

     Year
Ended
December 31,

2008
    Four Months
Ended
December 31,

2007
  

 

Years Ended August 31,

 
        2007     2006  

Current provision:

         

Federal

   $ (180 )   $ 2,990    $ 7,896     $ 27,640  

State

     12,241       5,831      10,432       1,987  
                               

Total

     12,061       8,821      18,328       29,627  

Deferred provision:

         

Federal

     (8,531 )     516      (7,494 )     (6,227 )

State

     278       612      557       (385 )
                               

Total

     (8,253 )     1,128      (6,937 )     (6,612 )
                               

Total Tax Provision

   $ 3,808     $ 9,949    $ 11,391     $ 23,015  
                               

On May 18, 2006, the State of Texas enacted House Bill 3 which replaced the existing state franchise tax with a “margin tax.” In general, legal entities that conduct business in Texas are subject to the Texas margin tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the margin tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. Therefore, we have accounted for Texas margin tax as income tax expense in the period subsequent to the law’s effective date of January 1, 2007. We recognized current state income tax expense related to the Texas margin tax of $10.5 million for the year ended December, 31, 2008, $3.9 million for the four months ended December 31, 2007 and $6.9 million for the year ended August 31, 2007. There is no comparable state tax expense for the year ended August 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 Partnerships. The principal sources of cash flow for the Parent Company are its direct and indirect investments in the limited and general partner

 

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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 $0.38 million as of December 31, 2008. The Parent Company is currently in discussions with ETP regarding the prospect of purchasing additional ETP Common Units as discussed below.

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.

In September 2007, ETE filed a registration statement on Form S-3 with the SEC to register the offer and sale of Common Units held by selling unitholders as well as $2.00 billion aggregate offering price of Common Units that may be offered and sold by ETE from time to time. This registration statement became effective in October 2007. ETE has not made any sales under this registration statement. ETE filed a Prospectus Supplement under SEC Rule 424(b)(3), dated January 24, 2008, to update information relating to the resale from time to time by the selling unitholders of up to 66,625,100 of ETE’s Common Units.

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:

 

 

growth capital expenditures for our intrastate operations mainly for constructing new pipelines and compression for which we expect to spend between $390.0 million and $410.0 million during 2009;

 

 

growth capital expenditures, excluding capital contributions to the MEP and FEP projects as discussed below, for the construction of new pipelines and pipeline expansions for our interstate operations, for which we expect to spend between $350.0 million and $375.0 million during 2009;

 

 

capital contributions to MEP and FEP;

 

   

With respect to MEP, capital expenditures currently are being funded under a project financing arrangement, although the project facility is expected to reach its limit in early 2009, after which we will be required to make capital contributions to complete the project. We expect to make capital contributions to MEP of between $400.0 million and $420.0 million during 2009 to fund our portion of MEP’s capital expenditures. In addition, we expect that we will need to make a capital contribution of approximately $260.0 million whenever MEP obtains permanent financing. MEP’s existing credit facility is available until February 2011;

 

   

In October 2008, we announced the FEP project, as discussed in Note 3 of our consolidated financial statements. FEP intends to pursue separate financing for this project; however, the availability of such financing is uncertain. Excluding project financing, we expect that our capital contributions to FEP will be between $200.0 million and $220.0 million during 2009;

 

 

growth capital expenditures for our propane operations of approximately $36.8 million during 2009;

 

 

maintenance capital expenditures of approximately $130.0 million, 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; and

 

 

any potential acquisition capital expenditures, including acquisition of new pipeline systems and propane operations.

 

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ETP generally funds its capital expenditures 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.

Although we have recently completed equity and debt offerings, current economic conditions make it difficult to obtain funding in either the debt or equity markets. The current constraints in the capital markets may affect our and ETP’s ability to obtain funding through new borrowings or the issuance of Common Units. In addition, we and ETP expect that, to the extent we are successful in arranging new debt financing, we and ETP will incur increased costs associated with these debt financings. In light of the current market conditions, we and ETP have taken steps to preserve our liquidity position including, but not limited to, reducing discretionary capital expenditures, maintaining our cash distribution rate for the fourth quarter of 2008 at the same level as the prior quarter and continuing to appropriately manage operating and administrative costs to improve profitability. ETP has also recently increased the available capacity under the ETP Credit Facility by using aggregate proceeds of approximately $821.9 million from ETP’s December 2008 Senior Notes and January 2009 ETP Common Units offerings to repay outstanding borrowings. As of December 31, 2008, in addition to approximately $91.9 million of cash on hand, we had available capacity under the Parent Company’s credit facilities and the ETP Credit Facility of $1.42 billion ($1.27 billion on a pro forma basis after giving effect to the $225.9 million of net proceeds from ETP’s equity offering in January 2009). We expect to utilize these resources, along with cash from ETP’s operations, to fund our announced growth capital expenditures for 2009 and working capital needs during 2009. In addition to these sources of liquidity, we may also access the debt and equity markets during 2009 in order to provide additional liquidity to fund growth capital expenditures for future years or for other partnership purposes.

ETP will continue to evaluate a variety of financing sources in order to fund its future growth capital expenditures and working capital needs, including funds available under our existing revolving credit facility, funds raised from future equity and/or debt offerings and funds raised from other sources, which sources may include project financing or other alternative financing arrangements from third parties or affiliated parties. In this regard, ETP has initiated discussions with us regarding the prospect of our purchasing additional ETP Common Units from ETP. We have an aggregate of approximately $378.4 million of cash on hand and available borrowing capacity under our revolving credit facility as of December 31, 2008.

ETP believes that the size and scope of its operations, its stable asset base and cash flow profile and its investment grade status will be significant positive factors in efforts to obtain new debt and equity funding; however, there is no assurance that we or ETP will be successful in obtaining financing under any of the alternatives discussed above if current capital market conditions continue for an extended period of time or if markets deteriorate further from current conditions. Furthermore, the terms, size and cost of any one of these financing alternatives could be less favorable and could be impacted by the timing and magnitude of our funding requirements, market conditions, and other uncertainties.

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 other than those expenditures necessary to maintain the service capacity of ETP’s existing assets. 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.

ETP manages its exposure to increased pipe costs by purchasing steel and reserving mill space, as projects are approved, in advance of construction. However, there is no assurance that ETP will not be impacted by increased pipe costs and limited mill space.

ETP engages in natural gas storage transactions in which it seeks to find and profit from pricing differences that occur over time. Natural gas is typically purchased and held in storage during the summer months and sold during the winter months. Although ETP intends to fund natural gas purchases with cash generated from operations, from time to time it may need to finance the purchase of natural gas to be held in storage with borrowings from its current credit facilities. ETP intends to repay these borrowings with cash generated from operations when the gas is sold.

 

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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.

Operating Activities. Cash provided by operating activities during the year ended December 31, 2008, was $823.8 million as compared to cash provided by operating activities of $754.5 million for the year ended August 31, 2007. The difference between net income and the net cash provided by operations for the year ended December 31, 2008 consisted of non-cash charges of $317.1 million (principally depreciation and amortization, minority interests and subsidiary distributions to minority unitholders) and changes in operating assets and liabilities of $131.6 million. Various components of operating assets and liabilities changed significantly from the prior period including factors such as the timing of accounts receivable collections, payments on accounts payable, the timing of the purchase and sale of propane and natural gas inventories, and the timing of advances and deposits received from customers.

Investing Activities. Cash used in investing activities during the year ended December 31, 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.

Financing Activities. Cash provided by financing activities was $1.23 billion for the year ended December 31, 2008. We received $373.0 million in net proceeds from equity offerings of ETP (see Note 7 to our consolidated financial statements). Proceeds from the equity offerings were used to repay borrowings from the ETP Credit Facility. We also received net proceeds of approximately $2.08 billion from the issuance by ETP of new senior notes (see Note 6 to our consolidated financial statements) which were used to repay other indebtedness. During the year ended December 31, 2008, we had a net increase in our debt level of $1.32 billion primarily to fund our growth capital expenditures and for general partnership purposes. During the year ended December 31, 2008, we paid distributions of $435.9 million to our partners related to the four-month transition period ended December 31, 2007 and the quarters ended March 31, 2008, June 30, 2008, and September 30, 2008.

Financing and Sources of Liquidity

In January 2008, ETP issued 750,000 Common Units at $48.81 per Common Unit to underwriters pursuant to the exercise of a 30-day option to purchase additional Common Units to cover over-allotments in connection with its December 2007 public offering of 5,000,000 Common Units. The net proceeds from the option exercise of $35.0 million, were used to repay outstanding borrowings under the ETP Credit Facility (defined below).

In March 2008, ETP issued a total of $1.50 billion aggregate principal amount of ETP 2008 Senior Notes (defined below). The proceeds of approximately $1.48 billion (net of bond discounts of $8.2 million and other offering costs of $10.8 million) from the issuance of the ETP 2008 Senior Notes were used to repay other indebtedness.

In July 2008, ETP issued 8,912,500 Common Units at $39.45 per Common Unit in a public offering. Net proceeds of approximately $338.0 million from the offering, including the capital contribution from ETP’s general partner to maintain its 2% general partner’s interest, were used to repay outstanding borrowings under the ETP Credit Facility.

On January 27, 2009, ETP issued 6,900,000 Common Units representing limited partner interests at $34.05 per Common Unit in a public offering. Net proceeds of approximately $225.9 million from the offering were used to repay outstanding borrowings under the ETP Credit Facility.

In December 2008, ETP issued a total of $600.0 million aggregate principal amount of 9.70% Senior Notes due 2019. The proceeds of approximately $595.7 million (net of bond discounts of $0.4 million and other offering costs of $3.9 million) from the issuance of the ETP 9.70% Senior Notes were used to repay indebtedness under the ETP Credit Facility, to pay expenses associated with the offering of the Notes, and for general partnership purposes.

 

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Description of Indebtedness

ETE’s consolidated indebtedness as of December 31, 2008 includes the Parent Company’s Senior Secured Credit Agreement which includes a $1.45 billion Senior Secured Term Loan Facility available through November 1, 2012 and a $500.0 million Senior Secured Revolving Credit Facility available through February 8, 2011. ETP has $4.05 billion aggregate principal amount of Senior Notes comprised of $600.0 million in principal amount of 9.70% Senior Notes due 2019, $350.0 million in principal amount of 6.00% Senior Notes due 2013, $600.0 million in principal amount of 6.70% Senior Notes due 2018, $550.0 million in principal amount of 7.50% Senior Notes due 2038, $750.0 million in principal amount of 5.95% Senior Notes due 2015, $400.0 million in principal amount of 5.65% Senior Notes due 2012, $400.0 million in principal amount of 6.125% Senior Notes due 2017 and $400.0 million in principal amount of 6.625% Senior Notes due 2036, each described below (collectively, the “ETP Senior Notes”), and the ETP Credit Facility, a revolving credit facility that allows for borrowings of up to $2.00 billion (expandable to $3.00 billion) available through July 20, 2012. ETP also has separate indebtedness at Transwestern and HOLP. The terms of our indebtedness and our subsidiaries are described in more detail below and in Note 6 to our consolidated financial statements. Failure to comply with the various restrictive and affirmative covenants of the credit agreements could negatively impact our ability and the ability of our subsidiaries to incur additional debt and our subsidiaries’ ability to pay distributions. We are required to measure these financial tests and covenants quarterly and, as of December 31, 2008, we were in compliance with all financial requirements, tests, limitations, and covenants related to financial ratios under our existing credit agreements. See “Debt Covenants” below.

Parent Company Indebtedness

The Parent Company has a $1.45 billion Term Loan Facility with a Term Loan Maturity Date of November 1, 2012 (the “Parent Company Credit Agreement”). The Parent Company Credit Agreement also includes a $500.0 million Secured Revolving Credit Facility (the “Parent Company Revolving Credit Facility”) available through February 8, 2011. The Parent Company Revolving Credit Facility includes a Swingline loan option with a maximum borrowing of $10.0 million and a daily rate based on LIBOR.

The total outstanding amount borrowed under the Parent Company Credit Agreement and the Parent Company Revolving Credit Facility as of December 31, 2008 was $1.57 billion. The total amount available under the Parent Company’s debt facilities as of December 31, 2008 was $0.38 million. The Parent Company Revolving Credit Facility also contains an accordion feature which will allow the Parent Company, subject to lender approval, to expand the facility’s capacity up to an additional $100.0 million.

The maximum commitment fee payable on the unused portion of the Parent Company Revolving Credit Facility is based on the applicable Leverage Ratio which is currently at Level III or 0.375%. Loans under the Parent Company Revolving Credit Facility bear interest at Parent Company’s option at either (a) the Eurodollar rate plus the applicable margin or (b) base rate plus the applicable margin. The applicable margins are a function of the Parent Company’s leverage ratio that corresponds to levels set-forth in the agreement. The applicable Term Loan bears interest at (a) the Eurodollar rate plus 1.75% per annum and (b) with respect to any Base Rate Loan, at Prime Rate plus 0.25% per annum. At December 31, 2008, the weighted average interest rate was 4.11% for the amounts outstanding on the Parent Company Senior Secured Revolving Credit Facility and the Parent Company $1.45 billion Senior Secured Term Loan Facility.

The Parent Company Credit Agreement is secured by a lien on all tangible and intangible assets of the Parent Company and its subsidiaries including its ownership of 62.5 million ETP Common Units, the Parent Company’s 100% interest in ETP LLC and ETP GP with indirect recourse to ETP GP’s 2% General Partner interest in ETP and 100% of ETP GP’s outstanding incentive distribution rights in ETP, which the Parent Company holds through its ownership in ETP GP. The financial covenants contained in the revolving credit facility include a leverage ratio test, a consolidated leverage ratio test, an interest coverage ratio test and a value-to-loan ratio. Please see Note 6 to our consolidated financial statements included under Item 8 of this Form 10-K for further discussion of the covenants.

 

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ETP Indebtedness

ETP 9.70% Senior Notes

In December 2008, ETP completed a public offering of $600.0 million aggregate principal amount of the ETP 9.70% Senior Notes due 2019 (the “ETP 9.70% Senior Notes”). The holders of the ETP 9.70% Senior Notes have the right to require us to repurchase all or a portion of the notes on March 15, 2012 at the principal amount plus any accrued interest as of that date. ETP used the proceeds of approximately $595.7 million, net of bond discounts and other offering costs, from the issuance of the ETP 9.70% Senior Notes to repay other indebtedess.

Interest on the ETP 9.70% Senior Notes is payable semiannually on March 15 and September 15 of each year. The Partnership may redeem some or all of the ETP 9.70% Senior Notes at any time, or from time to time, pursuant to the terms of the indenture.

ETP 2008 Senior Notes

In March 2008, ETP issued a total of $1.50 billion aggregate principal amount of Senior Notes comprised of $350.0 million of 6.00% Senior Notes due 2013, $600.0 million of 6.70% Senior Notes due 2018, and $550.0 million of 7.50% Senior Notes due 2038 (collectively, the “ETP 2008 Senior Notes”). ETP used the proceeds of approximately $1.48 billion (net of bond discounts of $8.2 million and other offering costs of $10.8 million) from the issuance of the ETP 2008 Senior Notes to repay borrowings and accrued interest outstanding under the $500.0 million, 364-day term loan credit facility (the “ETP 364-Day Credit Facility”) and to repay a portion of amounts outstanding under the ETP Credit Facility. Interest on the ETP 2008 Senior Notes is payable semiannually on January 1 and July 1 of each year. The Partnership may redeem some or all of the ETP 2008 Senior Notes at any time, or from time to time, pursuant to the terms of the indenture. The ETP 364-Day Credit Facility was a single draw term loan used for general corporate purposes, under which ETP borrowed the entire amount available under this facility on February 12, 2008, with an applicable Eurodollar rate plus 1.000% per annum based on the current rating by the rating agencies or at the Base Rate for a designated period. The indebtedness under the ETP 364-Day Credit Facility was unsecured and not guaranteed by us, ETP, or any of our or ETP’s subsidiaries.

ETP 2006 Senior Notes

In October 2006, we issued a total of $400.0 million of 6.125% Senior Notes due 2017 and $400.0 million of 6.625% Senior Notes due 2036 (collectively, the “ETP 2006 Senior Notes”). Interest on the senior notes due 2017 is payable semi-annually on February 15 and August 15 of each year, beginning February 15, 2007, and interest on the senior notes due 2036 is payable semi-annually on April 15 and October 15 of each year, beginning April 15, 2007.

ETP 2005 Senior Notes

In July 2005, we issued a total of $400.0 million of 5.65% Senior Notes due 2012 (the “ETP 5.65% Senior Notes”). Interest on the ETP 5.65% Senior Notes is payable semi-annually on February 1 and August 1 of each year, beginning on February 1, 2006.

In January 2005, we issued a total of $750.0 million of 5.95% Senior Notes due 2015 (the “ETP 5.95% Senior Notes,” and collectively with the ETP 5.65% Senior Notes, the “ETP 2005 Senior Notes”). Interest on the ETP 5.95% Senior Notes is payable semi-annually on February 1 and August 1 of each year, beginning on August 1, 2005.

The ETP Senior Notes were issued under an indenture and related indenture supplements containing covenants, which, among other things, restrict ETP’s ability to, subject to certain exceptions, incur debt secured by liens, engage in sale-leaseback transactions or merge or consolidate with another entity or sell substantially all of our assets. The ETP Senior Notes are unsecured obligations of ETP and the obligation of ETP to repay the ETP Senior Notes is not guaranteed by us, ETP, or any of our or ETP’s subsidiaries. As a result, the ETP Senior Notes effectively rank junior to any future indebtedness of ETP’s or its subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP Senior Notes effectively rank junior to all indebtedness and other liabilities of its existing and future subsidiaries.

Transwestern Senior Unsecured Notes

Transwestern’s long-term debt consists of $213.0 million remaining principal amount of notes assumed in connection with the Transwestern acquisition and $307.0 million in principal amount of notes issued in May 2007, the proceeds from which were used to repay other indebtedness and for general corporate purposes. No principal payments are required under any of the Transwestern notes prior to their respective maturity dates. The Transwestern notes rank pari passu with Transwestern’s other unsecured debt. The Transwestern notes are prepayable at any time in whole or pro rata in part, subject to a premium or upon a change of control event, as defined.

 

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Transwestern’s credit agreements contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and require certain debt to capitalization ratios.

HOLP Senior Secured Notes

All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP and its subsidiaries secure the HOLP Senior Secured, Medium Term, and Senior Secured Promissory Notes (collectively, the “HOLP Notes”). In addition to the stated interest rate for the HOLP Notes, we are required to pay an additional 1% per annum on the outstanding balance of the HOLP Notes at such time as the HOLP Notes are not rated investment grade status or higher. As of December 31, 2008 the HOLP Notes were rated investment grade or better thereby alleviating the requirement that we pay the additional 1% interest.

Revolving Credit and Short-Term Debt Facilities

ETP Credit Facility

The ETP Credit Facility is a $2.00 billion revolving credit facility that is expandable to $3.00 billion (subject to obtaining the approval of the administrative agent and securing lender commitments for the increased borrowing capacity) which matures on July 20, 2012, unless we elect the option of one-year extensions (subject to the approval of each such extension by the lenders holding a majority of the aggregate lending commitments). Amounts borrowed under the ETP Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The ETP Credit Facility includes a swingline loan option of which borrowings and aggregate principal amounts shall not exceed the lesser of (i) the aggregate commitments ($2.00 billion unless expanded to $3.00 billion) less the sum of all outstanding revolving credit loans and the letter of credit obligation and (ii) the swingline commitment. The aggregate amount of swingline loans in any borrowing shall not be subject to a minimum amount or increment. The indebtedness under the ETP Credit Facility is prepayable at any time at the Partnership’s option without penalty. The commitment fee payable on the unused portion of the ETP Credit Facility varies based on our credit rating and the fee is 0.11% based on our current rating with a maximum fee of 0.125%.

As of December 31, 2008, there was a balance outstanding on the ETP Credit Facility of $902.0 million in revolving credit loans with no outstanding balance in swingline loans, and approximately $60.0 million in letters of credit. The weighted average interest rate on the total amount outstanding at December 31, 2008, was 2.82%. The total amount available under the ETP Credit Facility, as of December 31, 2008, which is reduced by any letters of credit, was approximately $1.04 billion ($1.27 billion on a pro forma basis after giving effect to the $225.9 million of net proceeds from our equity offering in January 2009). The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our other current and future unsecured debt. In connection with entering into the credit agreement for the ETP Credit Facility (July 2007), all guarantees by ETC OLP, Titan and their direct and indirect wholly-owned subsidiaries of the ETP Senior Notes were released and discharged. The indebtedness under the ETP Credit Facility has the same priority of payment as our other current and future unsecured debt.

HOLP Credit Facility

A $75.0 million Senior Revolving Facility (the “HOLP Credit Facility”) is available to HOLP through June 30, 2011 which may be expanded to $150.0 million. The HOLP Facility includes a swingline loan option with a maximum borrowing of $10.0 million at a prime rate. Amounts borrowed under the HOLP Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the facility varies based on the Leverage Ratio, as defined, with a maximum fee of 0.50%. The agreement includes provisions that may require contingent prepayments in the event of dispositions, loss of assets, merger or change of control. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts of HOLP, and the capital stock of HOLP’s subsidiaries secure the HOLP Credit Facility (total book value as of December 31, 2008 of approximately $1.3 billion). At December 31, 2008, there was $10.0 million outstanding on the revolving credit loans. A letter of credit issuance is available to HOLP for up to 30 days prior to the maturity date of the HOLP Credit Facility. There were outstanding letters of credit $1.0 million at December 31, 2008. The sum of the loans made under the HOLP Credit Facility plus the letter of credit exposure and the aggregate amount of all swingline loans cannot exceed the $75.0 million maximum amount of the HOLP Credit Facility. The amount available as of December 31, 2008 was $64.0 million.

 

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MEP Guarantee

On February 29, 2008, MEP entered into a credit agreement that provides for a $1.40 billion senior revolving credit facility (the “MEP Facility”). We have guaranteed 50% of the obligations of MEP under the MEP Facility, with the remaining 50% of MEP Facility obligations guaranteed by KMP. Subject to certain exceptions, our guarantee may be proportionately increased or decreased if our ownership percentage increases or decreases. The MEP Facility is available through February 28, 2011. Amounts borrowed under the MEP Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the MEP Facility varies based on both our credit rating and that of KMP, with a maximum fee of 0.15%. The MEP Facility also has a swingline loan option with a maximum borrowing of $25.0 million at a prime rate. The sum of the loans, swingline loans and letters of credit may not exceed the maximum amount of revolving credit available under the MEP Facility. The indebtedness under the MEP Facility is prepayable at any time at the option of MEP without penalty. The MEP Facility contains covenants that limit (subject to certain exceptions) MEP’s ability to grant liens, incur indebtedness, engage in transactions with affiliates, enter into restrictive agreements, enter into mergers, or dispose of substantially all of its assets. The MEP Facility is syndicated among multiple financial institutions; the Royal Bank of Scotland PLC is the administrative agent. Among the lending banks that make up the syndicate of financial institutions for the MEP Facility, affiliates of Lehman Brothers had committed to approximately $100.0 million of the $1.40 billion facility. As a result of the Lehman Brothers bankruptcy in 2008, the MEP Facility has effectively been reduced by the amount of the Lehman Brothers affiliates’ commitment. However, the MEP Facility is not in default, and the commitments of the other lending banks remain unchanged.

In March 2008, MEP reimbursed ETP a net $63.5 million from the MEP Facility for previous advances ETP made to MEP. As of December 31, 2008, MEP had $837.5 million of outstanding borrowings and $33.3 million of letters of credit issued under the MEP Facility. Our contingent obligations with respect to our 50% guarantee of MEP’s outstanding borrowings and letters of credit were $418.8 million and $16.7 million, respectively, as of December 31, 2008. The weighted average interest rate on the total amount outstanding as of December 31, 2008 was 3.1271%. The total amount available under the MEP Facility was $429.2 million as of December 31, 2008.

MEP previously had a $197.0 million reimbursement agreement under which MEP could issue letters of credit. This reimbursement agreement expired in and there are no longer any letters of credit outstanding.

Debt Covenants

The agreements related to the ETP Senior Notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations in liens and a restriction on sale-leaseback transactions. The agreements related to each of the HOLP Notes and the HOLP Credit Facility contain customary restrictive covenants applicable to ETP and the Operating Partnerships, including the maintenance of various financial and leverage covenants, limitations on substantial disposition of assets, changes in ownership, the level of additional indebtedness and creation of liens as described in more detail below.

The credit agreement relating to the ETP Credit Facility contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries ability to, among other things:

 

 

incur indebtedness;

 

 

grant liens;

 

 

enter into mergers;

 

 

dispose of assets;

 

 

make certain investments;

 

 

make Distributions (as defined in such credit agreement) during certain Defaults (as defined in such credit agreement) and during any Event of Default (as defined in such credit agreement);

 

 

engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;

 

 

engage in transactions with affiliates;

 

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enter into restrictive agreements; and

 

 

enter into speculative hedging contracts.

The credit agreement related to the ETP Credit Facility also contains a financial covenant that provides that on each date ETP makes a distribution, the leverage ratio, as defined in the ETP Credit Facility, shall not exceed 5.0 to 1, with a permitted increase to 5.5 to 1 during a specified acquisition period, as defined in the ETP Credit Facility.

The agreements related to the HOLP Notes and the HOLP Credit Facility contain customary restrictive covenants applicable to HOLP, including the maintenance of various financial and leverage covenants and limitations on substantial disposition of assets, changes in ownership, the level of additional indebtedness and creation of liens. The financial covenants require HOLP to maintain ratios of Adjusted Consolidated Funded Indebtedness to Adjusted Consolidated EBITDA (as these terms are similarly defined in the agreements related to the HOLP Notes and HOLP Credit Facility) of not more than 4.75 to 1 and Consolidated EBITDA to Consolidated Interest Expense (as these terms are similarly defined in the agreements related to the HOLP Notes and HOLP Credit Facility) of not less than 2.25 to 1. These debt agreements also provide that HOLP may declare, make, or incur a liability to make restricted payments during each fiscal quarter, if: (a) the amount of such restricted payment, together with all other restricted payments during such quarter, do not exceed the amount of Available Cash (as defined in the agreements related to the HOLP Notes and HOLP Credit Facility) with respect to the immediately preceding quarter (which amount is required to reflect a reserve equal to 50% of the interest to be paid on the HOLP Notes during the last quarter and in addition, in the third, second and first quarters preceding a quarter in which a scheduled principal payment is to be made on the HOLP Notes, and a reserve equal to 25%, 50%, and 75%, respectively, of the principal amount to be repaid on such payment dates), (b) no default or event of default exists before such restricted payments, and (c) the amounts of HOLP’s restricted payment is not disproportionately greater than the payment amount from ETC OLP utilized to fund payment obligations of ETP and its general partner with respect to ETP’s Common Units.

Failure to comply with the various restrictive and affirmative covenants of our bank credit facilities and the note agreements related to the HOLP Notes could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Partnerships’ ability to incur additional debt and/or our ability to pay distributions.

We are required to measure these financial tests and covenants quarterly and were in compliance with all requirements, tests, limitations, and covenants related to ETE’s, ETP’s, Transwestern’s and HOLP’s debt agreements as of December 31, 2008. ETP has previously announced various pipeline expansion projects for 2009, including the Katy expansion (expected to be in service by the end of the first quarter of 2009), the Phoenix project (completed in February 2009), the Midcontinent Express pipeline (first phase expected to be in service during the second quarter of 2009 and the second phase expected to be in service during the third quarter of 2009), and the Texas Independence pipeline (completion expected in the third quarter of 2009). ETP plans to fund its expansion capital expenditures, including the expansion projects expected to be completed in 2009 as well as other recently announced expansion projects, with cash flow from operations, proceeds from sales of its senior notes, borrowings under the ETP Credit Facility and/or proceeds from the sale of ETP Common Units. Please read “Risk Factors — Risks Related to Our Business — 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.” While we expect that financing for these expansion projects will result in an increase in our level of indebtedness in future quarters, we also expect that the incremental cash flow from the expansion projects expected to be completed in 2009 will allow ETP to satisfy the financial ratio covenants related to its existing debt during 2009.

Each of the agreements referred to above are incorporated herein by reference to ETP’s reports previously filed with the SEC under the Exchange Act. See Item 1, “Business – SEC Reporting.”

 

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Contractual Obligations

The following table summarizes our long-term debt and other contractual obligations as of December 31, 2008 (in thousands):

 

     Payments Due by Period

Contractual Obligations

   Total    Less Than
1 Year
   1-3 Years    3-5 Years    More Than
5 Years
              

Long-term debt

   $ 7,235,589    $ 45,232    $ 206,862    $ 3,147,308    $ 3,836,187

Interest on fixed rate long-term debt (a)

     4,097,248      307,958      637,148      604,179      2,547,963

Payments on derivatives

     264,142      142,432      88,558      23,684      9,468

Purchase commitments (b)

     259,483      256,901      2,582      —        —  

Operating lease obligations

     314,648      21,041      38,498      30,999      224,110
                                  

Totals

   $ 12,171,110    $ 773,564    $ 973,648    $ 3,806,170    $ 6,617,728
                                  

 

(a) See “Liquidity and Capital Resources – Revolving Credit and Short-Term Debt Facilities – MEP Guarantee.”
(b) Fixed rate interest on long-term debt includes the amount of interest due on our fixed rate long-term debt. These amounts do not include interest on our variable rate debt obligations which include our Revolving Credit Facilities and Revolving Credit Facility Swingline Loan options. As of December 31, 2008, variable rate interest on our outstanding balance of variable rate debt of $2.48 billion would be $90.3 million on an annual basis. See Note 6 – “Debt Obligations” to the consolidated financial statements in Item 8 of this report for further discussion of the long-term debt classifications and the maturity dates and interest rates related to long-term debt.
(c) We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We have long and short-term product purchase obligations for propane and energy commodities with third-party suppliers. These purchase obligations are entered into at either variable or fixed prices. The purchase prices that we are obligated to pay under variable price contracts approximate market prices at the time we take delivery of the volumes. Our estimated future variable price contract payment obligations are based on the December 31, 2008 market price of the applicable commodity applied to future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. The purchase prices that we are obligated to pay under fixed price contracts are established at the inception of the contract. Our estimated future fixed price contract payment obligations are based on the contracted fixed price under each commodity contract. Obligations shown in the table represent estimated payment obligations under these contracts for the periods indicated.

Cash Distributions

Cash Distributions Paid by the Parent Company

Under the Parent Company Partnership Agreement, the Parent Company will distribute all of its Available Cash, as defined, within 50 days following the end of each fiscal quarter. Available cash generally means, with respect to any 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 that is necessary or appropriate to provide for future cash requirements.

 

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Distributions declared since the Parent Company’s Initial Public Offering in February 2006 are as follows:

 

    

Record Date

   Payment Date    Amount per Unit

Calendar Year Ended December 31, 2008

   November 10, 2008    November 19, 2008    $ 0.4800
   August 7, 2008    August 19, 2008      0.4800
   May 5, 2008    May 19, 2008      0.4400
   February 1, 2008 (1)    February 19, 2008      0.5500

Transition Period Ended December 31, 2007

   October 5, 2007    October 19, 2007    $ 0.3900

Fiscal Year Ended August 31, 2007

   July 2, 2007    July 19, 2007    $ 0.3725
   April 9, 2007    April 16, 2007      0.3560
   January 4, 2007    January 19, 2007      0.3400
   October 5, 2006    October 19, 2006      0.3125

Fiscal Year Ended August 31, 2006

   June 30, 2006    July 19, 2006    $ 0.2375
   March 31, 2006    April 19, 2006      0.0578

On January 26, 2009, Parent Company announced the declaration of a cash distribution for the fourth quarter ended December 31, 2008 of $0.51 per Common Unit, or $2.04 annually, an increase of $0.12 per Common Unit on an annualized basis. We paid this distribution on February 19, 2009 to Unitholders of record at the close of business on February 6, 2009.

The total amount of distributions (all from Available Cash from the Parent Company’s operating surplus) declared during the periods ended as noted below are as follows (in thousands):

 

     Year
Ended
December 31,
2008
   Four Months
Ended
December 31,
2007
   Years Ended
August 31,
         2007    2006

Limited Partners -

           

Limited Partners

   $ —      $ —      $ —      $ 34,010

Common Units

     434,519      86,904      246,136      65,905

Class B Units

     —        —        1,645      745

Class C Units

     —        —        28,261      —  

General Partner

     1,349      270      955      599
                           

Total distributions declared

   $ 435,868    $ 87,174    $ 276,997    $ 101,259
                           

Cash Distributions Received by the Parent Company

Currently, the Parent Company’s only cash-generating assets are its direct and indirect partnership interests in ETP. These ETP interests consist of all of ETP’s 2% general partner interest, 100% of ETP’s incentive distribution rights and ETP Common Units held by the Parent Company.

The total amount of distributions the Parent Company received from ETP relating to its limited partner interests, general partner interest and Incentive Distribution Rights for the periods ended as noted below is as follows:

 

     Year Ended
December 31,
2008
    Four Months
Ended
December 31,
2007
   Years Ended August 31,  
        2007    2006  

Limited Partners Interests

   $