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UNITED STATES

FORM 10-K

EL PASO ENERGY PARTNERS, L.P.

Registrant’s telephone number, including area code: (713) 420-2600

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: NONE.

      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  þ     No  o

      Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     o

      The registrant had 39,738,974 common units outstanding as of February 27, 2002. The aggregate market value on such date of the registrant’s common units held by non-affiliates was approximately $1,393 million.

      Documents Incorporated by Reference: None

EL PASO ENERGY PARTNERS, L.P.

TABLE OF CONTENTS

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PART I

ITEM 1. BUSINESS

General

      Formed in 1993, we are one of the largest publicly traded master limited partnerships in terms of market capitalization. We currently manage a balanced, diversified portfolio of interests and assets that includes:

	•	oil and natural gas pipelines, platforms, processing facilities and other energy infrastructure assets in the deeper water regions of the Gulf of Mexico, primarily offshore Louisiana and Texas;
	•	intrastate natural gas pipeline assets in Alabama;
	•	Natural gas liquids (NGL) transportation and fractionation facilities in south Texas;
	•	natural gas processing facilities in New Mexico;
	•	natural gas and NGL storage facilities in Mississippi and Louisiana; and
	•	oil and natural gas properties in the Gulf of Mexico.

      Our objective is to operate as a growth-oriented master limited partnership with a focus on increasing our cash flow, earnings and return to our unitholders. Our strategy is to combine our position as a provider of midstream services in the deeper water regions of the Gulf of Mexico with an aggressive effort to acquire and develop diversified onshore midstream energy infrastructure assets. Our strategy also includes identifying opportunities that create synergies with the other assets and operations of El Paso Corporation, the indirect parent of our general partner. We intend to continue de-emphasizing our commodity-based activities, such as exploration and production operations, and to concentrate on fee-based operations, such as gathering, transportation, processing, storage and fractionation, which traditionally provide more stable cash flows. We intend to execute our business strategy by:

	•	capitalizing on our extensive infrastructure in the Gulf of Mexico and expanding our existing assets further into the deeper water regions with projects supported by new discoveries and long-term commitments;
	•	purchasing or constructing onshore pipelines, gathering systems, storage, processing and fractionation facilities and other midstream assets to provide a broad range of more stable, fee-based services to producers, marketers and users of energy products; and
	•	leveraging the nationwide asset base and operational expertise of El Paso Corporation.

      We regularly consider and enter into discussions regarding potential acquisitions, including those from El Paso Corporation or its subsidiaries, and expect to continue to do so in the future. In 2001, our cash outlay for investments of midstream energy infrastructure assets totaled $589 million. Assets acquired from El Paso Corporation and third parties totaled $344 million and $78 million, and funds expended for the construction of assets totaled $167 million.

As generally used in the energy industry and in this document, the following terms have the following meanings:

     When we refer to natural gas and oil in “equivalents,” we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one Bbl of oil is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at 14.73 pounds per square inch.

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     In February 2002, we agreed to acquire midstream businesses from El Paso Corporation. The primary businesses to be acquired include:

	•	the 9,400 mile EPGT Texas intrastate pipeline, with a capacity of approximately 5 Bcf/d and average throughput of 3,500 MDth/d during 2001;
	•	1,300 miles of gathering systems in the Permian Basin with a capacity of 465 MMcf/d and average net 2001 throughput of 341 MDth/d; and
	•	a 42.3 percent non-operating interest in the Indian Basin gas processing and treating plant and associated gathering lines.

      Total consideration for these transactions is approximately $750 million and will include the following consideration to subsidiaries of El Paso Corporation:

	•	the sale of our Prince tension leg platform (TLP) and the 9 percent overriding royalty interest in the Prince Field for approximately $190 million after our repayment of the related limited recourse debt of $95 million;
	•	the issuance of $6 million in common units; and
	•	a cash payment of $554 million.

      These amounts will be adjusted at closing for the value of working capital acquired or sold. We will retain third-party marketing rights for remaining platform capacity and an option to repurchase the TLP at the end of the Prince Field reserve life. We expect to finance the purchase of these businesses through debt and equity financing in accordance with our strategy to maintain a strong balance sheet. The transaction is expected to close in the first quarter of 2002 subject to receiving regulatory approvals and arranging satisfactory financing.

      Also in February 2002, we announced that we will build and operate the Cameron Highway Oil Pipeline System, a 380-mile oil pipeline in the Gulf of Mexico. Cameron Highway will deliver up to 500 MBbl/d of oil from the southern Green Canyon and western Gulf of Mexico areas to Port Arthur and Texas City, Texas. The new pipeline is expected to be in service by the third quarter of 2004. We have entered into agreements with operating subsidiaries of BP p.l.c., BHP Billiton, and Unocal under which each of them have dedicated production from the Holstein, Mad Dog, and Atlantis Deepwater Trend discoveries for transportation on Cameron Highway. We will seek a partner or partners for up to 50 percent of the interest in the pipeline.

      In January 2002, we acquired a 3.3 million barrel propane storage business and complete leaching operation located in Hattiesburg, Mississippi from Suburban Propane Partners, L.P. As part of the transaction, we entered into a long-term propane storage agreement with Suburban Propane Partners for a portion of the acquired propane storage capacity. We intend to convert a portion of these assets to natural gas storage and will integrate them with our adjacent Petal natural gas storage facility. In December 2001, we acquired Anse La Butte, a 3.2 million barrel NGL multi-product storage facility near Breaux Bridge, Louisiana. We entered into long-term storage agreements with a third party and a subsidiary of El Paso Corporation for a significant portion of the storage capacity.

      Also in December 2001, we announced an agreement with Anadarko Petroleum Corporation to jointly develop Anadarko’s Marco Polo discovery, using a floating production platform capable of accommodating production from multiple fields. In conjunction with this agreement, we formed a 50/50 joint venture to construct, install, and own the platform with Cal Dive International, Inc. The platform’s production capacity is expected to be 100 MBbls/d of oil and 250 Mcf/d of gas. Anadarko will have firm capacity of 50 MBbls/d of oil and 150 Mcf/d of gas. The remainder of the platform capacity will be available to Anadarko for additional production and/or to third parties that have fields developed in the area. Anadarko will operate the platform. We anticipate that the facilities will be completed in 2004.

      In October 2001, we acquired interests in the titleholder of, and other interests in, the Chaco cryogenic natural gas processing plant, the third largest natural gas processing plant in the United States measured by liquids produced. The Chaco plant is a state-of-the-art cryogenic plant located in the San Juan Basin in New Mexico. It is capable of processing up to 700 Mdth/d of natural gas and handling up to 50 MBbls/d of NGLs.

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      Also in October 2001, we agreed to install a new natural gas pipeline from our Viosca Knoll system to the deepwater Medusa development in the Gulf of Mexico. We also entered into an agreement to provide natural gas gathering services for Murphy Exploration and Production Company’s Medusa development. Construction of this pipeline is scheduled to begin in mid-2002, and first production from the Medusa development is anticipated by the fourth quarter of 2002. We also entered into an agreement to provide natural gas gathering services for TotalFinaElf’s Matterhorn, Camden Hills and Aconcagua discoveries located in the Gulf of Mexico Deepwater Trend. Natural gas production from these fields will be delivered to our Viosca Knoll system. First production from Camden Hills and Aconcagua is anticipated in the summer of 2002. First production from Matterhorn is anticipated in the third quarter of 2003.

      In February 2001, we acquired the south Texas fee-based NGL transportation and fractionation assets (EPN Texas) from a subsidiary of El Paso Corporation. These assets include more than 600 miles of NGL gathering and transportation pipelines, as well as three fractionation plants with a capacity of approximately 96 MBbls/d. These plants fractionate NGLs into ethane, propane and butane products, which are used by refineries and petrochemical plants along the Texas Gulf Coast.

      In January 2001, we agreed to sell our interests in several offshore Gulf of Mexico assets, including our interests in the Nautilus, Manta Ray Offshore, Nemo, Green Canyon and Tarpon natural gas pipeline systems, as well as interests in two offshore platforms. In addition, we and Deepwater Holdings agreed to sell our joint interests in the Stingray System, UT Offshore System (UTOS), and the West Cameron dehydration facility. These sales occurred as a result of a Federal Trade Commission (FTC) order relating to El Paso Corporation’s merger with The Coastal Corporation.

Segments

      We segregate our business activities into five segments:

	•	Natural Gas Gathering and Transportation;
	•	Liquid Transportation and Handling;
	•	Platforms;
	•	Natural Gas Storage; and
	•	Oil and Natural Gas Production.

      These segments are strategic business units that provide a variety of energy related services. For information relating to operating revenues and operating income of each segment, see Item 8, Financial Statements and Supplementary Data, Note 13. Each of these segments is discussed more fully below.

Natural Gas Gathering and Transportation

      Our pipeline systems extend over 870 miles and have a combined maximum design capacity of over 3.4 Bcf/d of natural gas. Our offshore natural gas pipeline systems are strategically located to serve production activities in some of the most active drilling and development regions in the Gulf of Mexico, including select locations offshore of Texas, Louisiana and Mississippi, and to provide relatively low cost access to long-line transmission pipelines that access multiple markets in the eastern half of the United States. In addition to our offshore natural gas pipeline systems, we have a gathering system that serves the coal bed methane producing regions of Alabama and a small pipeline lateral in New Mexico. The following table and discussions describe our natural gas pipelines, all of which we wholly-own and operate.

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(1)	The average throughput reflects 100 percent of the throughput. Prior to October 2001, we owned a 50 percent interest in HIOS and East Breaks through Deepwater Holdings. We acquired the remaining 50 percent interest in October 2001 from subsidiaries of El Paso Corporation.
(2)	All capacity measures are on a MMcf/d basis.
(3)	All average throughput measures are on a MDth/d basis. For the pipelines described above, one MDth is substantially equivalent to one MMcf.

     Viosca Knoll System. The Viosca Knoll system is an offshore natural gas gathering system designed to serve the Main Pass, Mississippi Canyon and Viosca Knoll areas of the Gulf of Mexico and consists of 125 miles of predominantly 20-inch natural gas pipeline and a 7,000 horsepower compressor. During 1999, we acquired an additional 49 percent interest in the Viosca Knoll system, and in 2000 we acquired the remaining one percent from a subsidiary of El Paso Corporation, bringing our total interest in the Viosca Knoll system to 100 percent. The system provides its customers access to the facilities of a number of major interstate pipelines, including pipelines owned by Tennessee Gas Pipeline Company, Columbia Gulf Transmission Company, Southern Natural Gas Company, Transcontinental Gas Pipeline Company (Transco) and Destin Pipeline Company.

      HIOS. In October 2001, HIOS became a wholly-owned asset through our acquisition of the remaining 50 percent equity interest in Deepwater Holdings that we did not already own from subsidiaries of El Paso Corporation. HIOS is a natural gas transmission system regulated by the Federal Energy Regulatory Commission (FERC), that consists of 204 miles of pipeline. HIOS transports natural gas from producing fields located in the Galveston, Garden Banks, West Cameron, High Island, and East Breaks areas of the Gulf of Mexico to numerous downstream pipelines including the ANR and Tennessee Gas pipelines owned by El Paso Corporation.

      East Breaks System. In October 2001, East Breaks became a wholly-owned asset through our acquisition of the remaining 50 percent equity interest in Deepwater Holdings that we did not already own from subsidiaries of El Paso Corporation. East Breaks is a natural gas gathering system that consists of an 85-mile pipeline that connects HIOS to the Hoover-Diana project developed by subsidiaries of ExxonMobil and BP in the Alaminos Canyon and East Breaks areas of the Gulf of Mexico. East Breaks was placed in service in June 2000 and has the ability to expand its throughput capacity further, which would provide HIOS with the ability to compete for the right to gather and transport the substantial reserves associated with properties being, and expected to be, developed in these deepwater frontier regions.

      El Paso Intrastate-Alabama System. In March 2000, we acquired the EPIA system, a natural gas pipeline system that serves the coal bed methane producing regions of Alabama. The system consists of over 450 miles of pipeline. EPIA also provides marketing services through the purchase and resale of natural gas by purchasing natural gas from regional producers and others, and selling natural gas to local distribution companies and others.

      Indian Basin. The Indian Basin lateral, located in southeast New Mexico, was placed into service in June 2001. This ten mile lateral connects the 300 MMcf/d Indian Basin processing and treating plant to El Paso Field Services’ Carlsbad Gathering System. The lateral offers alternative market outlets to the Transwestern and El Paso Natural Gas pipeline systems.

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     Markets and Competition

      Each of our natural gas pipeline systems are located at or near natural gas production areas that are served by other pipelines. Our natural gas pipeline systems face competition from both regulated and unregulated systems. Some of these competitors are not subject to the same level of rate and service regulation as we are. Other competing pipelines, such as long-haul transporters, may have rate design alternatives unavailable to ours. Consequently, those competing pipelines may be able to provide service on more flexible terms and at rates significantly below those we offer.

      A majority of the revenues generated by our pipeline systems are attributed to production from reserves committed under long-term contracts for the productive life of the relevant field. Nonetheless, these reserves and other reserves that may become available to our pipeline systems are depleting assets and will be produced over a finite period. Each of our pipeline systems must access additional reserves to offset the natural decline in production from existing connected wells or the loss of any other production to a competitor. Furthermore, the rates we charge for our services are dependent on whether the relevant pipeline system is regulated or unregulated, the quality of the service required by the customer, and the amount and term of the reserve commitment by the customer. A majority of our offshore arrangements involve life-of-reserve commitments with both firm and interruptible components. Generally, we receive a price per dekatherm of natural gas handled.

     Regulatory Environment

      Our natural gas pipeline systems are subject to the Natural Gas Pipeline Safety Act of 1968, which establishes pipeline and liquified natural gas plant safety requirements. All of our offshore pipeline systems are subject to regulation under the Outer Continental Shelf Lands Act, which calls for nondiscriminatory transportation on pipelines operating in the outer continental shelf region of the Gulf of Mexico. All of our pipeline systems are subject to the National Environmental Policy Act and other environmental legislation. Each of the pipeline systems has a continuing program of inspection designed to keep all of our facilities in compliance with pollution control and pipeline safety requirements. We believe that our pipeline systems are in compliance with the applicable requirements of these regulations.

      Our HIOS system is also subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. HIOS operates under a separate FERC approved tariff that governs its operations, terms and conditions of service and rates. The natural gas pipelines industry has historically been heavily regulated by federal and state government and we cannot predict what further actions FERC, state regulators, or federal and state legislators may take in the future.

      In September 2001, FERC issued a Notice of Proposed Rulemaking (NOPR) that proposes to apply the standards of conduct governing the relationship between interstate pipelines and marketing affiliates to all energy affiliates. Since HIOS is an interstate facility as defined by the Natural Gas Act, the proposed regulations, if adopted by FERC, would dictate how HIOS conducts business and interacts with all energy affiliates of El Paso Corporation and us. We cannot predict the outcome of the NOPR, but adoption of the regulations in substantially the form proposed would, at a minimum, place administrative and operational burdens on us. Further, more fundamental changes could be required such as a complete organizational separation or sale of HIOS.

     Maintenance

      Each of our pipeline systems requires regular maintenance. The interior of the pipelines is maintained through the regular cleaning of the line of liquids that collect in the pipeline. Corrosion inhibitors are also injected into all of the systems through the flow stream on a continuous basis. To prevent external corrosion of the pipe, anodes are fastened to the pipeline itself at prescribed intervals, providing protection from moisture or sea water. Our HIOS and Viosca Knoll systems include platforms that are manned on a continuous basis. The personnel onboard these platforms are responsible for site maintenance, operations of the platform facilities, measurement of the oil or natural gas stream at the source of production and corrosion control.

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Liquid Transportation and Handling

     NGL Transportation and Fractionation Facilities

      In February 2001, we acquired EPN Texas from a subsidiary of El Paso Corporation. EPN Texas includes more than 600 miles of intrastate NGL gathering and transportation pipelines and three fractionation plants located in south Texas. The intrastate NGL pipeline system is comprised of 379 miles of pipeline used to gather and transport unfractionated NGLs from various processing plants to the Shoup Plant, located in Corpus Christi, the largest of EPN Texas’ three fractionators. The system also includes 177 miles of pipelines that deliver fractionated products such as ethane, propane and butane to refineries and petrochemical plants along the Texas Gulf Coast and to common carrier NGL pipelines. The three fractionation facilities have a combined capacity of approximately 96 MBbls/d.

      Utilization rates in the fractionation industry can fluctuate dramatically from month to month, depending on the needs of producers. The average annual utilization rate of the fractionation facilities for 2001, 2000, and 1999 was 73 percent, 89 percent, and 88 percent. We secured a commitment from a subsidiary of El Paso Corporation that the utilization rate of these facilities during 2001 would be at least 85 percent. This commitment expired on December 31, 2001.

     Natural Gas Processing Facility

      In October 2001, we acquired interests in the titleholder of, and other interests in, the Chaco cryogenic natural gas processing plant, the third largest natural gas processing plant in the United States measured by liquids produced. The Chaco plant is a state-of-the-art cryogenic plant located in the San Juan Basin in New Mexico that uses high pressures and extremely low temperatures to remove water, impurities and excess hydrocarbon liquids from the raw natural gas stream and to recover ethane, propane and the heavier hydrocarbons. It is capable of processing up to 700 MDth/d of natural gas and handling up to 50 MBbls/d of NGLs. The average utilization rate for the Chaco plant for the calendar years 2001, 2000, and 1999 was 89 percent, 91 percent, and 93 percent. The average utilization rate from our acquisition date of October 18, 2001 to December 31, 2001, was 93 percent.

     Offshore Oil Pipeline Systems

      We have interests in two offshore oil pipeline systems, which extend over 300 miles and have a combined capacity of 480 MBbls/d of oil with the addition of pumps and the use of friction reducers. In addition to being strategically located in the vicinity of some prolific producing regions in the Gulf of Mexico, our oil pipeline systems are parallel to and interconnect with key segments of some of our natural gas pipeline systems and offshore platforms, which contain separation and handling facilities. This distinguishes us from our competitors by allowing us to provide some producing properties with a unique single point of contact through which they may access a wide range of midstream services and assets.

      Poseidon System. Poseidon is a major offshore sour crude oil pipeline system built in response to the increased demand for additional sour crude oil pipeline capacity in the central Gulf of Mexico. We own an effective 36 percent interest in Poseidon and began operating this system in January 2001. Poseidon has a maximum design capacity of 400 MBbls/d with the addition of pumps and the use of friction reducers. Our average net throughput was 56 MBbls/d, 57 MBbls/d, and 61 MBbls/d for the years ended December 31, 2001, 2000 and 1999. The Poseidon system consists of:

	•	117 miles of 16-inch to 20-inch diameter pipeline extending from our 50 percent owned Garden Banks 72 platform to our 50 percent owned Ship Shoal 332 platform;
	•	122 miles of 24-inch diameter pipeline extending from the Ship Shoal 332 platform to Houma, Louisiana;
	•	32 miles of 16-inch diameter pipeline extending from Ewing Bank Block 873 to the 24-inch pipeline in the area of South Timbalier Block 212; and

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	•	17 miles of 16-inch pipeline extending from Garden Banks Block 260 to South Marsh Island Block 205.

      Allegheny System. Our Allegheny system is an offshore crude oil system consisting of 43 miles of 14-inch diameter pipeline that connects the Allegheny field in the Green Canyon area of the Gulf of Mexico with Poseidon at our 50 percent owned Ship Shoal 332 platform. Allegheny has an approximate capacity of 80 MBbls/d and our average throughput was 13 MBbls/d, 18 MBbls/d, and 12 MBbls/d for the years ended December 31, 2001, 2000 and 1999. Oil production from the Allegheny field is committed to this system. The Allegheny system was placed into service in October 1999.

     Markets and Competition

      Utilization of our processing and fractionation facilities occurs only when the producer can receive more net proceeds by physically separating and selling the NGL components contained in the raw natural gas stream than they would receive by merely selling the raw natural gas stream. The spread between the prices for natural gas and NGLs is greatest when the demand for NGLs increases, which often occurs in the winter. If, and when, this spread becomes too narrow to justify the costs, producers will choose to sell the raw natural gas stream rather than process and fractionate, and our fractionation facilities will be underutilized.

      In connection with our acquisition of EPN Texas, we entered into a 20-year fee-based transportation and fractionation agreement and have dedicated 100 percent of the capacity of our fractionation facilities to a subsidiary of El Paso Corporation. In this agreement, all of the NGLs derived from processing operations at seven natural gas processing plants in south Texas owned by subsidiaries of El Paso Corporation are delivered to our NGL transportation and fractionation facilities. Effectively, we will receive a fixed fee for each barrel of NGLs transported and fractionated by our facilities. Approximately 25 percent of our per barrel fee is escalated annually for increases in inflation. El Paso Corporation’s subsidiary will bear substantially all of the risks and rewards associated with changes in the commodity prices for NGLs.

      In connection with the Chaco transaction, we entered into a 20-year fee-based processing agreement with El Paso Field Services. In accordance with the original construction financing agreements, the Chaco plant is under an operating lease to El Paso Field Services. They have the right to purchase the Chaco Plant at the end of the lease term in October 2002 for approximately $77 million. If El Paso Field Services does not exercise this repurchase right, it must pay us a forfeiture penalty. If El Paso Field Services does exercise this repurchase right, our rights and obligations under the 20-year agreement, including our right to a fixed fee for each dekatherm of natural gas processed at the Chaco plant will remain in place for the term of the agreement and will expire upon the termination of the agreement.

      Our offshore oil pipeline systems were built as a result of the need for additional crude oil capacity to transport new deepwater oil production to shore. Our principal competition includes other oil pipeline systems, built, owned and operated by producers to handle their own production and, as capacity is available, production for others. Our oil pipelines compete for new production on the basis of geographic proximity to the production, cost of connection, available capacity, transportation rates and access to onshore markets. In addition, the ability of our pipelines to access future reserves will be subject to our ability, or the producers’ ability, to fund the significant capital expenditures required to connect to the new production.

      A substantial portion of the revenues generated by our oil pipelines systems are attributed to production from reserves committed under long-term contracts for the productive life of the relevant field. Nonetheless, these reserves and other reserves that may become available to our pipeline systems are depleting assets and will be produced over a finite period. Each of our pipeline systems must access additional reserves to offset the natural decline in production from existing connected wells or the loss of any other production to a competitor. Furthermore, the rates we charge for our services are dependent on the quality of the service required by the customer and the amount and term of the reserve commitment by the customer. A majority of our offshore arrangements involve life-of-reserve commitments with both firm and interruptible components. Generally, we receive a price per barrel of oil or water handled.

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     Regulatory Environment

      Our offshore oil pipeline systems are subject to regulation under the Outer Continental Shelf Lands Act, which calls for nondiscriminatory transportation on pipelines operating in the outer continental shelf region of the Gulf of Mexico. All of our oil pipeline systems are subject to the National Environmental Policy Act and other environmental legislation. Each of the oil pipeline systems has a continuing program of inspection designed to keep all of our facilities in compliance with pollution control and pipeline safety requirements. We believe that our oil pipeline systems are in compliance with the applicable requirements of these regulations.

     Maintenance

      Each of our pipeline systems, our fractionation facilities and our processing facilities require regular maintenance. The interior of the EPN Texas, Allegheny and Poseidon pipelines is maintained through the regular cleaning of the line of liquids that collect in the pipeline. Corrosion inhibitors are also injected into all of the systems through the flow stream on a continuous basis. Our Allegheny and Poseidon oil pipeline systems include platforms that are manned on a continuous basis. The personnel on board these platforms are responsible for site maintenance, operations of the platform facilities, measurement of the oil stream at the source of production and corrosion control. Our Chaco processing facility is manned on a continuous basis by personnel who are also responsible for maintenance and operations. The maintenance of the facility is an ongoing process, which is performed based on the hours of operation, oil analysis and vibration hours. Shutdown of the Chaco plant is not required for regular maintenance activity.

Platforms

      Offshore platforms are critical components of the offshore infrastructure in the Gulf of Mexico, supporting drilling and production operations, and therefore play a key role in the overall development of offshore oil and natural gas reserves. Platforms are used to:

	•	interconnect the offshore pipeline grid;
	•	provide an efficient means to perform pipeline maintenance;
	•	locate compression, separation, production handling and other facilities; and
	•	conduct drilling operations during the initial development phase of an oil and natural gas property.

      We have interests in six multi-purpose offshore platforms in the Gulf of Mexico, including five multi-purpose hub-platforms and one multi-purpose TLP in the Prince Field, which was installed in July 2001 and accepted initial production in September 2001. These platforms were specifically designed to be used as deepwater hubs and production handling and pipeline maintenance facilities. Through these facilities, we are able to provide a variety of midstream services to increase deliverability and attract new volumes into our offshore pipeline systems. The following table and discussions describe our platforms.

(1)	The Ship Shoal 331 platform is currently used as a satellite landing area. All products transported to the Ship Shoal 331 platform are processed on the Ship Shoal 332 platform.
(2)	We sold 50 percent of our interest in the Ship Shoal 332 platform in January 2001.

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     Prince TLP. In July 2001, we placed in service our newly-constructed Prince TLP. The Prince TLP has a state-of-the-art design, which accommodates a workover rig and four to five wellhead connections above sea level and up to three subsea wellhead connections. El Paso Production, a subsidiary of El Paso Corporation, has committed all of the oil and natural gas it produces from the Prince Field to our Prince TLP and related pipelines and separating and handling facilities, for which we receive a fixed monthly demand charge as well as a commodity charge for the volumes of natural gas, oil and water produced from the Prince Field. The Prince TLP has the capacity to accommodate a 1,200-horsepower completion rig. The deck is equipped for the future addition of numerous sub-sea well tie-backs. First production flowed through the Prince TLP in September 2001. As part of our pending agreement to acquire assets from El Paso Corporation in the first quarter of 2002, we agreed to sell the Prince TLP to a subsidiary of El Paso Corporation.

      East Cameron 373. The East Cameron 373 platform is located at the south end of the central leg of Shell’s Stingray pipeline system. The platform serves as the host for Kerr-McGee Corporation’s East Cameron Block 373 production and as the landing site for Garden Banks Blocks 108, 152 and 200 production.

      Viosca Knoll 817. The Viosca Knoll 817 platform is centrally located on the Viosca Knoll system. The platform serves as a base for landing deepwater production in the area, including ExxonMobil’s, Shell’s, and BP’s Ram Powell development. A 7,000 horsepower compressor on the platform facilitates deliveries from the Viosca Knoll system to multiple downstream interstate pipelines. The platform is also used as a base for oil and natural gas production from our Viosca Knoll Block 817 lease.

      Ship Shoal 331. The Ship Shoal 331 platform is a production facility located approximately 75 miles off the coast of Louisiana. Pogo Producing Company has rights to utilize the platform pursuant to a production handling and use of space agreement.

      Garden Banks 72. The Garden Banks 72 platform is located at the south end of the eastern leg of Shell’s Stingray pipeline system and serves as the western-most termination point of the Poseidon system. The platform serves as a base for landing deepwater production from Enterprise Oil Gulf of Mexico, Inc.’s and Devon Energy Inc.’s Garden Banks Block 161 development and Mariner Energy Inc.’s development in Garden Banks Block 73, and will serve as the host for Amerada Hess Corporation’s Garden Banks Block 158 development. We also use this platform as the host for our Garden Banks Block 72 production and the landing site for production from our Garden Banks Block lease located in an adjacent lease block.

      Ship Shoal 332. The Ship Shoal 332 platform serves as a major junction platform for pipelines in the Allegheny and Poseidon systems.

  Markets and Competition

      Our platforms are subject to similar competitive factors as our natural gas and oil pipeline systems. These assets generally compete on the basis of proximity and access to existing reserves and pipeline systems, as well as costs and rates. Furthermore, competitors to these platforms may possess greater technical skill and capital resources than we have.

  Maintenance

      Each of our platforms requires regular maintenance. The platforms are painted to the waterline every three to five years to prevent atmospheric corrosion. Corrosion protection devices are also fastened to platform legs below the waterline to prevent corrosion. Remotely operated vehicles or divers inspect the platforms below the waterline generally every five years. Most of our platforms are manned on a continuous basis. The personnel on board these platforms are responsible for site maintenance, operations of the platform facilities, measurement of the oil and natural gas stream at the source of production and corrosion control.

Natural Gas Storage

      We own the Crystal salt dome natural gas storage businesses located in Mississippi, which are strategically situated to serve the Northeast, Mid-Atlantic and Southeast natural gas markets. The two primary facilities, Petal and Hattiesburg, have a combined current working capacity of 6.7 Bcf, and are

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      The Hattiesburg facility is comprised of 73 acres outside of Hattiesburg, Mississippi, and consists of three salt caverns with a working gas capacity of approximately 3.5 Bcf. The Petal facility is comprised of 16.5 acres, is less than one mile from the Hattiesburg facility and consists of a single high-deliverability natural gas storage cavern with a working gas capacity of approximately 3.2 Bcf. The Petal facility is designed to provide up to 320 MMcf/d of 10-day storage services with the capability of being refilled in 20 days. The Petal capacity is currently fully subscribed, primarily with short-term contracts. The Hattiesburg facility has an injection capacity in excess of 175 MMcf/d of natural gas and a withdrawal capacity in excess of 350 MMcf/d of natural gas. The Hattiesburg capacity is currently fully subscribed, primarily with long-term contracts expiring between 2005 and 2006. The ability of these facilities to handle high levels of injections and withdrawals of natural gas makes the facilities well suited for customers who desire the ability to meet short duration load swings and to cover major supply interruption events, such as hurricanes and temporary losses of production. The high injection and withdrawal rates also allow customers to take advantage of price savings in natural gas by allowing for quick delivery. The characteristics of the salt domes at the facilities permit sustained periods of high delivery, the ability to quickly switch from full injection to full withdrawal and the ability to provide an impermeable storage medium.

      The FERC has approved a 6.8 Bcf expansion of the Petal facility, as well as a 60-mile pipeline addition that will interconnect with the storage facility and offer direct interconnects with the Southern Natural Gas, Transco and Destin pipeline systems. The additional Petal capacity is dedicated under a 20-year fixed-fee contract to a subsidiary of The Southern Company, one of the largest producers of electricity in the United States. We expect to complete the first-phase of the Petal facility expansion and the construction of the pipeline addition in mid-2002.

      Competition for natural gas storage is primarily based on location and the ability to deliver natural gas in a timely and reliable manner. Our Petal and Hattiesburg natural gas storage facilities are located in an area in Mississippi that can effectively service the Northeastern, Mid-Atlantic and Southeastern natural gas markets, and the facilities have the ability to deliver all of their stored natural gas within a short timeframe. Our natural gas storage facilities compete with other means of natural gas storage, including other salt dome storage facilities, depleted reservoir facilities, liquified natural gas and pipelines.

      Most of the contracts relating to our Hattiesburg natural gas storage assets are long term, expiring between 2005 and 2006. We believe that the existence of these long-term contracts for storage, the proposed expansion of our operations and the location of our natural gas storage facilities should allow us to compete effectively with other companies who provide natural gas storage services. We believe that many of our natural gas storage contracts will be renewed, although we also expect that once these firm storage contracts have expired, we will experience greater competition for providing storage services. The competition we experience will be dependent upon the nature of the natural gas storage market existing at that time. In addition to long-term contracts, we actively market interruptible storage services at the Petal facility to enhance our revenue generating ability beyond the firm storage contracts.

  Regulatory Environment

      Our Hattiesburg facility is a regulated utility under the jurisdiction of the Mississippi Public Service Commission. Accordingly, the rates charged for natural gas storage services are subject to approval from this agency. The present rates of the firm long-term contracts for natural gas storage in the Hattiesburg facility were approved in 1990. A portion of its natural gas storage business is also subject to a limited jurisdiction certificate issued by FERC. The certificate authorizes us to provide natural gas storage services that may be ultimately consumed outside of Mississippi. Our Petal facility is subject to regulation under the Natural Gas Act of 1938, as amended, and to the jurisdiction of FERC. The Petal facility currently holds certificates of

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      In September 2001, FERC issued a NOPR that proposes to apply the standards of conduct governing the relationship between interstate pipelines and marketing affiliates to all energy affiliates. Since Petal is an interstate facility as defined by the Natural Gas Act, the proposed regulations, if adopted by FERC, would dictate how Petal conducts business and interacts with all energy affiliates of El Paso Corporation and us. We cannot predict the outcome of the NOPR, but adoption of the regulations in substantially the form proposed would, at a minimum, place administrative and operational burdens on us. Further, more fundamental changes could be required such as a complete organizational separation or sale of Petal.

Oil and Natural Gas Production

      Currently, we own interests in six oil and natural gas properties located in waters offshore of Louisiana. Production is gathered, transported, and processed through our pipeline systems and platform facilities and is sold to various third parties and subsidiaries of El Paso Corporation.

(1)	We own a 2.5 percent overriding interest in Garden Banks Block 73, which began producing in mid 2000.
(2)	Our working interest in Viosca Knoll Block 817 is subject to a production payment that entitles holders to 25 percent of the proceeds from the production attributable to this working interest (after deducting all leasehold operating expenses, including platform access and production handling fees) until the holders have received the aggregate sum of $16 million. At December 31, 2001, the unpaid portion of the production payment obligation totaled $9.4 million.
(3)	The West Delta Block 35 field commenced production in 1993, but our interest in this field was acquired in connection with El Paso Corporation’s acquisition of our general partner in 1998. Production data is for the period from August 1998.
(4)	We own a 9 percent net overriding royalty interest in the Prince Field.

     We currently own a 9 percent net overriding royalty interest in the Prince Field, formerly the Ewing Bank 958 Unit. Production from the Prince Field, which is committed to our Prince TLP, commenced in September 2001. As part of our pending agreement to acquire assets from El Paso Corporation in the first quarter of 2002, we agreed to sell this overriding royalty interest to a subsidiary of El Paso Corporation.

      Acreage and Wells. The following table sets forth our developed and undeveloped oil and natural gas acreage as of December 31, 2001. Undeveloped acreage refers to those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether or not such acreage contains proved reserves. Gross acres in the following

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      Our gross and net ownership in producing wells in which a working interest is owned directly by us at December 31, 2001, is as follows:

      We participated through our 38 percent non-operating working interest in a developmental well in West Delta Block 35 in 2001. As an operator, we have not drilled any exploratory or developmental wells since 1998 and do not intend to drill any development or exploratory wells in the future.

     Net Production, Unit Prices and Production Costs

      The following table sets forth information regarding the production volumes of, average unit prices received for, and average production costs for our oil and natural gas properties for the years ended December 31:

(1)	The information regarding net production and average realized sales prices includes overriding royalty interests. Average realized oil and natural gas sales prices for 2000 and 1999 were impacted by hedging activities.
(2)	The components of average production costs, which consist of operating expenses per unit of oil or natural gas produced, may vary substantially among wells depending on the methods of recovery employed and other factors, but generally include third party transportation expenses, maintenance and repair, labor and utilities costs. The increase in per unit production costs from 1999 to 2000 was a result of production decline coupled with higher offshore oil and gas field servicing and production costs.

     The relationship between average sales prices and average production costs depicted by the table above is not necessarily indicative of true results of operations. For a discussion of oil and natural gas reserve information and estimated future net cash flows, see Item 8, Financial Statements and Supplementary Data, Note 16.

     Markets and Competition

      We are reducing our oil and natural gas production activities due to its higher risk profile, including risks associated with finding production and commodity prices. Accordingly, our focus is to maximize the production from our existing portfolio of oil and natural gas properties. As a result, the competitive factors that would normally impact exploration and production activities are not as pertinent to our operations. However, the oil and natural gas industry is intensely competitive, and we do compete with a substantial number of other companies, including many with larger technical staffs and greater financial and operational resources in terms of accessing transportation, hiring personnel, marketing production and withstanding the effects of general and industry-specific economic changes.

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  Regulatory Environment

      Our production and development operations are subject to regulation at the federal and state levels. Regulated activities include:

	•	requiring permits for the drilling of wells;
	•	maintaining bonds and insurance requirements in order to drill or operate wells;
	•	drilling and casing wells;
	•	the surface use and restoring of properties upon which wells are drilled; and
	•	plugging and abandoning of wells.

      Our production and development operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled, the levels of production, and the pooling of oil and natural gas properties.

      We presently have interests in, or rights to, offshore leases located in federal waters. Federal leases are administered by the Minerals Management Service (MMS). Individuals and entities must qualify with the MMS prior to owning and operating any leasehold or right-of-way interest in federal waters. Qualification with the MMS generally involves filing certain documents and obtaining an area-wide performance bond and/or supplemental bonds representing security for facility abandonment and site clearance costs.

     Operating Environment

      Our oil and natural gas production operations are subject to all of the operating risks normally associated with the production of oil and natural gas, including blowouts, cratering, pollution and fires, each of which could result in damage to life or property. Offshore operations are subject to usual marine perils, including hurricanes and other adverse weather conditions, and governmental regulations, including interruption or termination by governmental authorities based on environmental and other considerations. In accordance with customary industry practices, we maintain broad insurance coverage with respect to potential losses resulting from these operating hazards.

Major Encumbrances

      Substantially all of our assets, with the exception of Argo, L.L.C., and Argo I, L.L.C., together with our management agreement, and our general partner’s one percent general partner interest, are pledged as collateral under our existing revolving credit facility. Substantially all of Argo’s assets are pledged under Argo’s limited recourse term loan. In addition, Poseidon, our equity investee, currently has a credit facility under which substantially all of its assets are pledged. For a discussion of our credit facilities, see Item 8, Financial Statements and Supplementary Data, Note 6.

Environmental

      A description of our environmental matters is included in Item 8, Financial Statements and Supplementary Data, Note 10.

Employees

      Employees of El Paso Corporation, through our general partner, perform all of our administrative and operational activities under a management agreement. Therefore, we had no direct employees at December 31, 2001. We reimburse our general partner for all reasonable general and administrative expenses and other reasonable expenses incurred by our general partner and its affiliates for, or on our behalf, including, but not limited to, expenses incurred by our general partner under this management agreement.

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ITEM 2. PROPERTIES

      A description of our properties is included in Item 1, Business.

      We believe we have satisfactory title to the properties owned and used in our businesses, subject to liens for current taxes, liens incident to minor encumbrances, and easements and restrictions that do not materially detract from the value of the property, or the interests of the property, or the use of such properties in our businesses. We believe that our physical properties are adequate and suitable for the conduct of our business in the future.

ITEM 3. LEGAL PROCEEDINGS

      See Item 8, Financial Statements and Supplementary Data, Note 10.

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

      None.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S UNITS AND RELATED UNITHOLDER MATTERS

      Our common units are traded on the New York Stock Exchange (NYSE) under the symbol “EPN”. As of February 27, 2002, there were approximately 686 holders of record of common units.

      The following table reflects the high and low sales prices for common units based on the daily composite listing of stock transactions for the New York Stock Exchange and cash distributions declared per common and publicly held preference units during those periods.

(1)	As of October 2000, all publicly held preference units were converted into common units or redeemed.

     In January 2002, we declared a quarterly distribution of $0.625 per common unit which was paid on February 15, 2002, to unitholders of record on January 31, 2002. This increase in our quarterly distribution rate represents an annual increase of $0.05 per unit to an annual distribution rate of $2.50 per unit.

Cash Distributions

      We make quarterly distributions of 100 percent of our available cash, as defined in the partnership agreement, to our unitholders and to our general partner. Our available cash consists generally of all cash receipts plus reductions in reserves less all cash disbursements and net additions to reserves. Our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to the unitholders and our general partner, reserves to reduce debt, or, as necessary, reserves to comply with the terms of any of our agreements or obligations.

      The holders of common units and our general partner are not entitled to arrearages of minimum quarterly distributions. Our distributions are effectively made 99 percent to limited unitholders and one percent to our general partner, subject to the payment of incentive distributions to our general partner if certain target cash distribution levels to common unitholders are achieved. Incentive distributions to our general partner increase to 14 percent, 24 percent and 49 percent based on incremental distribution thresholds. Since 1998, quarterly distributions to common unitholders have been in excess of the highest incentive threshold of $0.425 per unit, and as a result, our general partner has received 49 percent of the incremental amount. For the year ended December 31, 2001, we paid $80.9 million in distributions to our common unitholders, including El Paso Corporation, and $25.5 million to our general partner related to incentive distributions as well as our general partner’s one percent income distribution. We issued Series B preference units in 2000 and beginning in the fourth quarter of 2010, any unpaid accruals occurring after September 2010 on these preference units will be currently payable and must be completely paid, prior to any distributions on common units. See Item 8, Financial Statements and Supplementary Data, Note 8, for a discussion relating to cash distributions.

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Public Offering of Common Units

      In October 2001, we completed offerings of 5,627,070 common units, which included a public offering of 4,150,000 common units and a private offering at the same unit price of 1,477,070 common units to our general partner which was an exempt transaction under Section 4(2) of the Securities Act of 1933, as amended, as a transaction not involving a public offering. We used the net cash proceeds of approximately $212 million to redeem 44,608 Series B preference units with an aggregate liquidation value of $50 million and to reduce indebtedness under our revolving credit facility by $162 million. In addition, our general partner contributed $2.1 million in cash to us in order to satisfy its one percent capital contribution requirement.

      In March 2001, we completed a public offering of 2,250,000 common units. We used the net cash proceeds of $66.6 million from the offering to reduce the balance outstanding under our revolving credit facility. In addition, our general partner contributed $0.7 million to us in order to satisfy its one percent capital contribution requirement.

      In July 2000, we completed a public offering of 4,600,000 common units that included 600,000 common units to cover over-allotments for the underwriters. We used the net cash proceeds of approximately $101 million from the offering to reduce the balance outstanding under our revolving credit facility. In addition, our general partner contributed $1.1 million to us in order to satisfy its one percent capital contribution requirement.

Series B Preference Units

      In August 2000, we issued to a subsidiary of El Paso Corporation $170 million of cumulative redeemable Series B preference units in exchange for the Crystal natural gas storage businesses. These preference units are non-voting and have rights to income allocations on a cumulative basis, compounded semi-annually at an annual rate of 10%. We are not obligated to pay cash distributions on these units until 2010. After September 2010, the rate will increase to 12% and preference income allocation after 2010 will be required to be paid on a current basis; accordingly, after September 2010, we will not be able to make distributions on our common units unless all unpaid accruals occurring after September 2010 on our then-outstanding Series B preference units have been paid. The preference units contain no mandatory redemption obligation, but may be redeemed at our option at any time. The issuance of these preference units was an exempt transaction under Section 4(2) of the Securities Act of 1933 as a transaction not involving a public offering. In October 2001, we redeemed 44,608 of the Series B preference units for their liquidation value of $50 million, bringing the total number of units outstanding to 125,392. As of December 31, 2001, the liquidation value of the outstanding Series B preference units was approximately $143 million.

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ITEM 6. SELECTED FINANCIAL DATA

(1)	Our operating results and financial position reflect the acquisitions of:

	•	the Chaco plant and the remaining 50 percent interest we did not already own in Deepwater Holdings in October 2001;
	•	EPN Texas in February 2001;
	•	the Crystal natural gas storage businesses in August 2000;
	•	EPIA in March 2000; and
	•	an additional 49 percent interest in Viosca Knoll in June 1999.

The acquisitions were accounted for as purchases and therefore operating results of these acquired entities are included in our results prospectively from the purchase date. In addition, operating results and financial position reflect the sale of our and Deepwater Holdings’ interests in several offshore Gulf of Mexico assets in January and April of 2001 as a result of an FTC order related to El Paso Corporation’s merger with The Coastal Corporation.

(2)	Operating revenues for 1999, 1998, and 1997 have been restated to exclude earnings from unconsolidated affiliates. The operating revenues in 1998 were affected by lower realized prices on oil and natural gas and inclement weather conditions which decreased production volumes.
(3)	Reflects impairment charges for capitalized costs written off in 1997 as a result of the abandonment of flow lines connecting to wells abandoned by third party owners.

(4)	Reflects our 1999 adoption of a preferable accounting method for allocating partnership income to our general partner and our preference and common unitholders. See Item 8, Financial Statements and Supplementary Data, Note 1, for further information.
(5)	In October 2000, all publicly held preference units were converted into common units or redeemed.
(6)	Relates to a project finance loan to build the Prince TLP in the Prince Field. With the completion of the Prince TLP, we converted the project finance loan to a limited recourse loan in December 2001.
(7)	The increase in 2001 reflects the issuance of our $250 million 8 1/2% Senior Subordinated Notes in May 2001. The increase in 1999 reflects the issuance of our $175 million 10 3/8% Senior Subordinated Notes in May 1999.
(8)	Reflects the issuance of:

	•	5.6 million common units, which included 1.5 million common units purchased by our general partner in October 2001;
	•	2.3 million common units in March 2001;
	•	$170 million Series B preference units to a subsidiary of El Paso Corporation in August 2000; and
	•	4.6 million common units in July 2000.

	In addition, we redeemed $50 million liquidation value of our Series B preference units in October 2001.

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General

      Our objective is to operate as a growth-oriented master limited partnership with a focus on increasing our cash flow, earnings and return to our unitholders. We intend to concentrate on fee-based operations, such as gathering, transportation, processing, storage and fractionation and to de-emphasize our commodity-based activities, such as exploration and production operations. Our strategy is to combine our position as a provider of midstream energy services in the deeper water regions of the Gulf of Mexico with an aggressive effort to acquire and develop diversified onshore midstream energy infrastructure assets.

      Our strategy contemplates substantial growth through the acquisition and development of a wide range of midstream and other energy infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance our ability to compete effectively, diversify our asset portfolio and, thereby, provide more stable cash flow. In addition to potential third-party acquisitions, El Paso Corporation has midstream assets that may be considered for sale to us. Our strategy has been and will continue to be expanding our operating scope, our ability to generate cash flow and our investment opportunities. Consequently, we have expanded our credit facilities, obtained project financing and issued debt and equity securities to meet our financial needs over the past three years. We will need substantial new capital to continue to finance our strategy, including additional future uses of periodic debt and equity offerings. Significant milestones in the implementation of our strategy over the past three years include:

      Our general partner, which is owned by El Paso Corporation, manages our day-to-day operations and strategic direction. Employees of El Paso Corporation perform all of our administrative and operational activities under our management agreement or, in some cases, separate operational agreements. Additionally, El Paso Corporation elects all of our general partner’s directors.

      We often enter into transactions with El Paso Corporation and its subsidiaries to acquire or sell assets, and have instituted specific procedures for evaluating and valuing these transactions. Before we consider entering into a transaction with El Paso Corporation or any of its subsidiaries, we determine that the proposed transaction (i) would comply with the requirements under our indentures and credit agreements, (ii) would

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	•	evaluates and, where appropriate, negotiates the proposed transaction;
	•	engages an independent financial advisor and independent legal counsel to assist with its evaluation of the proposed transaction; and
	•	determines whether to approve and recommend the proposed transaction.

      We will only consummate any proposed transaction with El Paso Corporation if, following its evaluation of the transaction, the Special Conflicts Committee approves and recommends the proposed transaction.

Acquisitions, Divestitures and Projects

Gulf of Mexico Assets

      In accordance with an FTC order related to El Paso Corporation’s merger with The Coastal Corporation, we, along with Deepwater Holdings, agreed to sell several of our offshore Gulf of Mexico assets to third parties in January 2001. Total consideration received for these assets was approximately $163 million consisting of approximately $109 million for the assets we sold and approximately $54 million for the assets Deepwater Holdings sold. The offshore assets sold include interests in Stingray, UTOS, Nautilus, Manta Ray Offshore, Nemo, Tarpon and the Green Canyon pipeline assets, as well as interests in two offshore platforms and one dehydration facility. We recognized net losses from the asset sales of approximately $12 million, and Deepwater Holdings recognized losses of approximately $21 million. Our share of Deepwater Holdings’ losses was approximately $14 million, which has been reflected in earnings from unconsolidated affiliates in the accompanying statements of income.

      As additional consideration for the above transactions, El Paso Corporation agreed to make payments to us totaling $29 million. These payments, which began in the first quarter of 2001, will be made in quarterly installments of $2.25 million for the next three years and $2 million in the first quarter of 2004. From this additional consideration, we recognized income of approximately $25 million in the first quarter of 2001, which has been reflected in other income in the accompanying statements of income.

EPN Texas

      In February 2001, we purchased EPN Texas from a subsidiary of El Paso Corporation for approximately $133 million. These assets include more than 600 miles of NGL gathering and transportation pipelines, as well as three fractionation plants with a capacity of approximately 96 MBbls/d. These plants fractionate NGLs into ethane, propane, and butane products which are used by refineries and petrochemical plants along the Texas Gulf Coast.

Prince TLP

      In July 2001, we installed the Prince TLP facility in the Prince Field. The platform was installed in 1,450 feet of water approximately 120 miles south of New Orleans, Louisiana. We also own the related pipelines to gather and process oil and natural gas production from the Prince Field. The platform will serve as a landing spot for future oil and natural gas developments in the Ewing Bank and Green Canyon areas of the Deepwater Trend of the Gulf of Mexico. The Prince TLP platform has a capacity of 50 MBbls/d of oil and 80 MMcf/d of natural gas, as well as the capacity to accommodate a 1,200-horsepower completion rig. The deck is equipped for the future addition of numerous sub-sea well tie-backs. The first production flowed through the facility in September 2001. As part of our pending agreement to acquire assets from El Paso Corporation, we agreed to sell the Prince TLP to a subsidiary of El Paso Corporation.

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Deepwater Holdings

      In October 2001, we acquired the remaining 50 percent equity interest that we did not already own in Deepwater Holdings, from a subsidiary of El Paso Corporation, for approximately $81 million, including $55 million of acquired indebtedness. At the acquisition date, we also repaid Deepwater Holdings’ outstanding revolving credit facility balance and terminated the facility. HIOS and East Breaks became indirect wholly-owned assets through this transaction.

Chaco Plant

      In October 2001, we acquired interests in the title holder of, and other interests in, the Chaco cryogenic natural gas processing plant, the third largest natural gas processing plant in the United States measured by liquids produced, for approximately $198.5 million. The total purchase price was comprised of:

	•	a payment of $77 million to acquire the Chaco plant from the bank group that provided the financing for the construction of the facility; and
	•	a payment of $121.5 million to El Paso Field Services in connection with the execution of a 20-year fee-based processing agreement relating to the processing capacity of the Chaco plant and dedication of natural gas gathered by El Paso Field Services.

      We receive a fixed fee from El Paso Field Services for each dekatherm of natural gas that we process. El Paso Field Services personnel continue to operate the plant. In accordance with the original construction financing agreements, the Chaco plant is under an operating lease to El Paso Field Services. El Paso Field Services has the right to purchase the Chaco plant at the end of the lease term in October 2002 for approximately $77 million. If El Paso Field Services does not exercise this repurchase right, it must pay us a forfeiture penalty. If El Paso Field Services does exercise this repurchase right, our rights and obligations under the 20-year agreement will remain in place for the term of the agreement and will expire upon the termination of the agreement.

Medusa Project

      In October 2001, we agreed to install a new natural gas pipeline from our Viosca Knoll system to the deepwater Medusa development in the Gulf of Mexico. We also entered into an agreement to provide natural gas gathering services for Murphy Exploration and Production Company’s Medusa development. Construction of this pipeline is scheduled to begin in mid-2002, and first production from the Medusa development is anticipated by the fourth quarter of 2002. The total cost of the project is estimated to be $28 million. We expect to fund the project through borrowings on our revolving credit facility.

Matterhorn Project

      In October 2001, we entered into an agreement to provide natural gas gathering services for TotalFinaElf’s Matterhorn, Camden Hills and Aconcagua discoveries located in the Gulf of Mexico Deepwater Trend. Natural gas production from these fields will be delivered to our existing Viosca Knoll system. First production from Camden Hills and Aconcagua is anticipated in the summer of 2002. First production from Matterhorn is anticipated in the third quarter of 2003.

NGL Storage Facility

      In December 2001, we acquired Anse La Butte, a 3.2 million barrel NGL multi-product storage facility near Breaux Bridge, Louisiana. As part of the transaction, we entered into long-term storage agreements, with a third party and a subsidiary of El Paso Corporation, for a significant portion of the storage capacity. In January 2002, we acquired a 3.3 million barrel propane storage business and leaching operation located in Hattiesburg, Mississippi from Suburban Propane Partners, L.P. As part of the transaction, we entered into a long-term propane storage agreement with Suburban Propane Partners for a portion of the acquired propane storage capacities. We intend to convert a portion of these assets to natural gas storage and will integrate them

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Marco Polo Project

      In December 2001, we announced an agreement with Anadarko Petroleum Corporation to jointly develop Anadarko’s Marco Polo discovery, using a floating production platform capable of accommodating production from multiple fields. In conjunction with this agreement, we formed a 50/50 joint venture to construct, install, and own the platform with Cal Dive International, Inc. The platform’s production capacity is expected to be 100 MBbls/d of oil and 250 Mcf/d of gas. Anadarko will have firm capacity of 50 MBbls/d of oil and 150 Mcf/d of gas. The remainder of the platform capacity will be available to Anadarko for additional production and/or to third parties that have fields developed in the area. Anadarko will operate the platform. We anticipate that the facilities will be completed in 2004.

      The total cost of the project is estimated to be $206 million, or approximately $103 million for our share. We expect to fund the majority of our share of the costs through non-recourse project debt financing.

Midstream Businesses

      In February 2002, we agreed to acquire midstream businesses from El Paso Corporation. The primary businesses to be acquired include:

	•	the 9,400 mile EPGT Texas intrastate pipeline, with a capacity of approximately 5 Bcf/d and average throughput of 3,500 MDth/d during 2001;
	•	1,300 miles of gathering system in the Permian Basin with a capacity of 465 MMcf/d and average throughput of 341 MDth/d during 2001; and
	•	a 42.3 percent non-operating interest in the Indian Basin gas processing and treating plant and associated gathering lines.

      Total consideration for these transactions is approximately $750 million and will include the following consideration to subsidiaries of El Paso Corporation:

	•	the sale of our Prince TLP and the 9 percent overriding royalty interest in the Prince Field for approximately $190 million after our repayment of the related limited recourse debt of $95 million;
	•	the issuance of $6 million in common units; and

      • a cash payment of $554 million.

      These amounts will be adjusted at closing for the value of working capital acquired or sold. We will retain third-party marketing rights for remaining platform capacity and an option to repurchase the TLP at the end of the Prince Field reserve life. We expect to finance the purchase of these businesses through debt and equity financing in accordance with our strategy to maintain a strong balance sheet. The transaction is expected to close in the first quarter of 2002 subject to receiving regulatory approvals and arranging satisfactory financing.

Cameron Highway Project

      In February 2002, we announced that we will build and operate the Cameron Highway Oil Pipeline System, a 380-mile oil pipeline in the Gulf of Mexico. Cameron Highway will deliver up to 500 MBbls/d of oil from the southern Green Canyon and western Gulf of Mexico areas to Port Arthur and Texas City, Texas. The new pipeline is expected to be in service by the third quarter of 2004. We have entered into agreements with operating subsidiaries of BP p.l.c., BHP Billiton, and Unocal under which each of them have dedicated production from the Holstein, Mad Dog, and Atlantis Deepwater Trend discoveries for transportation on Cameron Highway. We will seek a partner or partners for up to 50 percent of the $450 million total estimated cost. We expect to fund a majority of our share of the costs through non-recourse project financing. It is estimated that the majority of the capital outlay for the project will occur in 2003 and 2004.

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Results of Operations

      Our business activities are segregated into five segments:

	•	Natural Gas Gathering and Transportation;
	•	Liquid Transportation and Handling;
	•	Platforms;
	•	Natural Gas Storage; and
	•	Oil and Natural Gas Production.

      As a result of our acquisition of EPN Texas in February 2001, we began providing NGL transportation and fractionation services and have shown these activities as a separate segment called Liquid Transportation and Handling. This segment also includes the liquid transportation services of the Allegheny and Poseidon oil pipelines which were previously reflected in the Natural Gas Gathering and Transportation segment. The operating results of the Chaco plant are also included in the Liquid Transportation and Handling segment. All historical periods have been presented on the basis of the current segment presentation. Each of our segments is a strategic business unit that offers different services or products, and we manage each of these segments separately as they require different technology and marketing strategies. Since earnings from investments in unconsolidated affiliates can be a significant source of earnings in our segments, we have chosen to evaluate segment performance based on earnings before interest expense and taxes (EBIT).

      To the extent possible, results of operations have been reclassified to conform to the current business segment presentation, although these results may not be indicative of the results which would have been achieved had the revised business segment structure been in effect during those periods. Operating revenues and expenses by segment include intersegment revenues and expenses which are eliminated in consolidation. For a further discussion of the individual segments, see Item 8, Financial Statements and Supplementary Data, Note 13.

      The following table presents EBIT by segment and in total for each of the three years ended December 31:

Segment Results

      The Natural Gas Gathering and Transportation segment includes the Viosca Knoll system, the HIOS system, the East Breaks system, the EPIA system and the Indian Basin lateral. The natural gas gathering and transportation pipelines primarily earn revenue from fixed-fee-based services or market-based rates usually related to the monthly natural gas price index for volume gathered. These pipelines typically involve life-of-reserve commitments with both firm and interruptible components. EPIA provides transportation services as well as marketing services through the purchase of natural gas from regional producers and others, and the sale of natural gas to local distribution companies and others. Beginning in 2001, we entered into fixed

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     Year Ended December 31, 2001 Compared to Year Ended December 31, 2000

      Natural gas gathering and transportation revenues for the year ended December 31, 2001, were $4.6 million higher than in 2000, primarily due to our consolidation of Deepwater Holdings in October 2001 and revenues received from our Indian Basin lateral which went into service in June 2001. These increases were partially offset by lower volumes on our Viosca Knoll system due to Tropical Storm Barry in August 2001 and the sale of the Tarpon and Green Canyon pipeline assets in January 2001. Natural gas sales margin, or natural gas sales less cost of natural gas, for the year ended December 31, 2001, was $1.8 million higher than in 2000 due to higher volumes on EPIA as a result of a full twelve months of our ownership in 2001 as well as larger spreads between our natural gas sales prices and the cost to purchase natural gas in 2001. We acquired EPIA in March 2000.

      Operating expenses for the year ended December 31, 2001, were $11.2 million higher than in 2000, primarily due to the consolidation of Deepwater Holdings in October 2001 and the abandonment and impairment of the Manta Ray pipeline in January 2001, partially offset by lower operating expenses resulting from the sales of assets in January 2001. We abandoned the Manta Ray pipeline as a result of our January 2001 sale of the Manta Ray Offshore system.

      Other income for the year ended December 31, 2001, was $5.2 million lower than in 2000, primarily due to lower earnings from unconsolidated affiliates of $20.0 million, which primarily relates to Deepwater Holdings’ sale of Stingray, UTOS, and the West Cameron dehydration facility and the sale of our interest in Nautilus and Manta Ray Offshore during the first six months of 2001 and the related losses on these sales. Also, we had a decrease in earnings from unconsolidated affiliates due to our consolidation of Deepwater Holdings in October 2001. Further contributing to the decrease in other income were net losses on sales of assets of $7.8 million due to the sales of our interests in the Tarpon and Green Canyon pipeline assets in

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     Year Ended December 31, 2000 Compared to Year Ended December 31, 1999

      Natural gas transportation revenues for the year ended December 31, 2000, were $8.6 million higher than in 1999, primarily due to the consolidation of Viosca Knoll in June 1999. Natural gas sales margin for the year ended December 31, 2000, was $6.4 million due to the purchase of EPIA in March 2000.

      Operating expenses for the year ended December 31, 2000, were $2.0 million lower than in 1999, primarily due to cost recoveries under our operating agreement with Deepwater Holdings relative to actual costs incurred.

      Other income for the year ended December 31, 2000, was $13.7 million lower than in 1999, primarily due to the consolidation of Viosca Knoll in June 1999 and a gain related to the sale of a portion of our interest in Deepwater Holdings in 1999 to ANR Pipeline as part of the formation of Deepwater Holdings as a 50/50 joint venture with ANR.

  Liquid Transportation and Handling

      The Liquid Transportation and Handling segment includes the NGL transportation pipelines and fractionation plants of EPN Texas, the Chaco cryogenic natural gas processing plant and the Poseidon and Allegheny offshore oil pipelines. The EPN Texas plants fractionate NGLs into ethane, propane, and butane products which are used by refineries and petrochemical plants along the Texas Gulf Coast. We receive a fixed fee for each barrel of NGLs transported and fractionated by the EPN Texas facilities from a subsidiary of El Paso Corporation. We have dedicated 100 percent of our capacity to this subsidiary. As part of the acquisition of EPN Texas fractionation assets and dedication of their capacity to a subsidiary of El Paso Corporation, we secured a commitment from this subsidiary that the 2001 utilization rate of these facilities would average at least 85 percent. The average utilization rate for 2001 was 73 percent, accordingly we have recorded a receivable of $1.8 million related to the shortage of committed volumes. This commitment terminated in 2001 and future revenue will reflect the actual number of barrels of NGLs transported and fractionated. The Chaco plant receives and processes natural gas from the San Juan Basin located in New Mexico. We receive a fixed fee for each dekatherm processed from a subsidiary of El Paso Corporation under a 20-year fee-based processing agreement. We have dedicated up to 100 percent of our capacity to this subsidiary. In addition to processing fees, we also receive monthly lease revenues from this subsidiary. The lease terminates in October 2002. The crude oil pipeline systems serve production activities in the Gulf of Mexico. Revenues from our oil pipelines are generated by production from reserves committed under long-term contracts for the productive life of the relevant field.

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     Year Ended December 31, 2001 Compared to Year Ended December 31, 2000

      Revenues for the year ended December 31, 2001, were $31.2 million higher and operating expenses were $12.6 million higher than in 2000, primarily due to the purchases of EPN Texas in February 2001 and the Chaco plant in October 2001. Excluding these acquisitions, revenues were down $1.2 million due to decreased volumes on Allegheny as a result of platform shut-ins attributable to maintenance and tropical storm activity in late 2001.

      Other income for the year ended December 31, 2001, was $3.8 million higher than in 2000, primarily due to an increase in earnings from unconsolidated affiliates related to lower average interest rates on Poseidon’s revolving credit facility in 2001 and lower earnings in 2000 resulting from Poseidon’s pipeline rupture in January 2000. Partially offsetting this increase was the receipt of business interruption insurance proceeds in 2000 related to the Poseidon pipeline rupture.

     Year Ended December 31, 2000 Compared to Year Ended December 31, 1999

      Revenues for the year ended December 31, 2000, were $6.3 million higher and operating expenses were $0.6 million higher than in 1999, primarily due to a full year of revenues in 2000 from the Allegheny system, which went into service in the fourth quarter of 1999.

      Other income for the year ended December 31, 2000, was $4.4 million lower than in 1999, primarily due to lower earnings from Poseidon as a result of a pipeline rupture in January 2000. Partially offsetting this decrease was the receipt of business interruption insurance proceeds in 2000 related to the Poseidon pipeline rupture.

  Platforms

      The Platform segment consists of the Prince TLP, East Cameron 373, Viosca Knoll 817, Garden Banks 72, Ship Shoal 331, and Ship Shoal 332 platforms. These offshore platforms are used to interconnect our offshore pipeline grid, assist in performing pipeline maintenance, and conduct drilling operations during the initial development phase of an oil or natural gas property. Platform revenues are based on fixed and commodity charges. Fixed fees are recognized during the month reserved by the customer, regardless of how much capacity is actually used. Commodity fees are variable in nature and recognized when the service is provided. As part of our pending agreement to acquire assets from El Paso Corporation in the first quarter of 2002, we agreed to sell the Prince TLP to a subsidiary of El Paso Corporation.