EL PASO ENERGY PARTNERS LP - 10-K Annual Report

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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, 2002

OR

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

For the transition period from __________ to__________

COMMISSION FILE NO. 1-11680

EL PASO ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)

DELAWARE 76-0396023
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)

4 GREENWAY PLAZA 77046
HOUSTON, TEXAS (Zip Code)
(Address of Principal Executive Offices)

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (832) 676-6152

INTERNET WEBSITE: WWW.ELPASOPARTNERS.COM

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 [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 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 AN ACCELERATED FILER (AS
DEFINED IN EXCHANGE ACT RULE 12B-2). YES [X] NO [ ]

THE REGISTRANT HAD 44,030,314 COMMON UNITS OUTSTANDING AS OF MARCH 24,
2003. THE AGGREGATE MARKET VALUE ON MARCH 24, 2003 AND JUNE 28, 2002 OF THE
REGISTRANT'S COMMON UNITS HELD BY NON-AFFILIATES WAS APPROXIMATELY $1,369
MILLION AND $1,403 MILLION.

DOCUMENTS INCORPORATED BY REFERENCE: NONE
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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 (MLP) in terms of market capitalization. Since El Paso
Corporation's initial acquisition of an interest in us in 1998, we have
diversified our asset base, stabilized our cash flow and decreased our financial
leverage as a percentage of total capital. We have accomplished this through a
series of acquisitions and development projects as well as four public offerings
of our common units. We manage a balanced, diversified portfolio of interests
and assets relating to the midstream energy sector, which involves gathering,
transporting, separating, handling, processing, fractionating and storing
natural gas, oil and natural gas liquids (NGL). This portfolio, which we
consider to be balanced due to its diversity of geographic locations, business
segments, customers and product lines, includes:

- offshore oil and natural gas pipelines, platforms, processing facilities
and other energy infrastructure in the Gulf of Mexico, primarily offshore
Louisiana and Texas;

- onshore natural gas pipelines and processing facilities in Alabama,
Colorado, Louisiana, Mississippi, New Mexico and Texas;

- onshore NGL pipelines and fractionation facilities in Texas; and

- onshore natural gas and NGL storage facilities in Mississippi, Louisiana
and Texas.

We are one of the largest natural gas gatherers, based on miles of
pipeline, in the prolific natural gas supply regions offshore in the Gulf of
Mexico and onshore in Texas and the San Juan Basin, which envelops a significant
portion of the four contiguous corners of Arizona, Colorado, New Mexico and
Utah. These regions, especially the deeper water regions of the Gulf of Mexico,
one of the United States' fastest growing natural gas producing regions, offer
us significant infrastructure growth potential through the acquisition and
construction of pipelines, platforms, processing and storage facilities and
other infrastructure. In 2002, the Gulf of Mexico accounted for approximately 25
percent of all natural gas production in the United States and the supply
regions accessed by our pipelines in Texas and the San Juan Basin accounted for
approximately 33 percent.
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As generally used in the energy industry and in this document, the following
terms have the following meanings:

/d = per day
Bbl = barrel
BBtu = billion British thermal units
Bcf = billion cubic feet
Dth = dekatherm
MBbls = thousand barrels
Mcf = thousand cubic feet

MDth = thousand dekatherms
MMBbls = million barrels
MMBtu = million British thermal units
MMcf = million cubic feet
MMDth = million dekatherms

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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Our objective is to operate as a growth-oriented MLP with a focus on
increasing cash flow, earnings and return to our unitholders by becoming one of
the industry's leading providers of midstream energy services. Our strategy
entails striving to continually enhance the quality of our cash flow by:

- maintaining a balanced and diversified portfolio of midstream energy
interests and assets;

- maintaining a sound capital structure;

- sharing capital costs and risks through joint ventures/strategic
alliances; and

- emphasizing fee-based operations and services for which the fees are not
traditionally linked to commodity prices (like gathering and
transportation) and managing commodity risks by using contractual
arrangements (like fixed-fee contracts and hedging and tolling
arrangements) and de-emphasizing our commodity-based activities
(including exiting the oil and natural gas production business by not
acquiring additional properties).

We intend to execute our business strategy by:

- constructing and acquiring onshore pipelines, gathering systems,
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;

- expanding our existing offshore asset base, supported by the dedication
of new discoveries and long-term commitments, to capitalize on the
accelerated growth of oil and natural gas supplies from the deeper water
regions of the Gulf of Mexico;

- operating at low cost by achieving economies of scale in select regions
through reinvesting in and expanding our organic growth opportunities, as
well as by acquiring new assets;

- sharing capital costs and risks through joint ventures/strategic
alliances, principally with partners with substantial financial resources
and strategic interests, assets and operations in the Gulf of Mexico,
especially in the deeper water, Flextrend and subsalt regions; and

- continuing to strengthen our solid balance sheet by seeking to finance
and/or refinance our growth, on average, with 50 percent equity so as to
provide the financial flexibility to fund future opportunities.

In 2002, our cash outlay for investments of midstream energy infrastructure
assets totaled $1.7 billion. Assets acquired from El Paso Corporation and third
parties totaled $1.5 billion and $19 million, and funds expended for the
construction of assets totaled $228 million.

Our partners in the Gulf of Mexico include integrated and large independent
energy companies with substantial offshore interests, operations and assets,
such as Shell Oil Products, U.S. and Marathon Pipeline Company. We have entered
into a letter of intent with Valero Energy Corporation, one of the top refining
and marketing companies in the United States, to be our partner in our Cameron
Highway Oil Pipeline project.

RECENT EVENTS

San Juan Acquisition

In November 2002, we acquired the San Juan assets from subsidiaries of El
Paso Corporation for $782 million, $766 million after adjustments for capital
expenditures and working capital. The acquired assets include a natural gas
gathering system located in the San Juan Basin of New Mexico, including El Paso
Corporation's remaining interest in the Chaco cryogenic natural gas processing
plant; NGL transportation and

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fractionation assets located in Texas; and an oil and natural gas gathering
system located in the deeper water regions of the Gulf of Mexico. The following
is a description of the San Juan assets.

- The assets located in the San Juan Basin include:

- approximately 5,300 miles of natural gas gathering pipelines, known as
the San Juan gathering system, with capacity of over 1.1 Bcf/d that is
connected to approximately 9,500 wells producing natural gas from the
San Juan Basin located in northwest New Mexico and southwest Colorado;

- approximately 250,000 horsepower of compression;

- the 58 MMcf/d Rattlesnake CO(2) treating facility;

- a 50 percent interest in Coyote Gas Treating, LLC, the owner of a 250
MMcf/d treating facility; and

- the remaining interests in the Chaco cryogenic natural gas processing
plant that we did not already own and the price risk management
positions related to this facility's operations.

- The offshore pipeline assets include:

- The Typhoon gas pipeline, a 35-mile, 20-inch natural gas pipeline
originating on the Chevron/BHP "Typhoon" platform in the Green Canyon
area of the Gulf of Mexico extending to the ANR Patterson System in
Eugene Island Block 371; and

- The Typhoon oil pipeline, a 16-mile, 12-inch oil pipeline originating on
the Chevron/BHP "Typhoon" platform and extending to a platform in Green
Canyon Block 19 with onshore access through various oil pipelines.

- The Texas NGL assets include:

- a 163-mile, 4 to 6-inch propane pipeline extending from Corpus Christi
to McAllen and the Hidalgo truck terminal facilities;

- the Markham butane shuttle, a 124-mile, 8-inch pipeline with capacity of
approximately 20 MBbls/d running between Corpus Christi and a leased
storage facility at Markham with capacity of approximately 3.8 MMBbls;

- a 49-mile, 6-inch pipeline with capacity of approximately 15 MBbls/d
extending from the Almeda fractionator to Texas City and the Texas City
terminal;

- the Almeda fractionator, a 24 MBbls/d fractionator consisting of two
trains, with both trains currently out of service, and related leased
storage facilities of approximately 14.3 MMBbls; and

- a 201-mile, 8 to 10-inch pipeline with capacity of approximately 35
MBbls/d extending from Corpus Christi to the Almeda fractionator in
Pasadena. This pipeline is currently out of service.

We are required to make approximately $49 million of capital expenditures
to place the 201-mile 8 to 10-inch pipeline back in service and make repairs and
upgrades on the Markham butane shuttle and the Almeda fractionator.

We financed our acquisition of the San Juan assets through long-term debt
and equity as outlined below (in millions):

Series C units.............................................. $350
Senior secured acquisition term loan........................ 238
Senior subordinated notes................................... 194
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Initial purchase price...................................... 782
Less working capital and capital expenditure adjustments.... 16
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Net purchase price.......................................... $766
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We issued 10,937,500 of our Series C units to El Paso Corporation for a
value of $350 million. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources" for
further discussion of the acquisition financing, including a description of the
Series C units. The remaining balance of the purchase price was paid in cash. We
funded the cash portion of the purchase price with net proceeds of $238 million
from a senior secured acquisition term loan and $194 million from our issuance
of senior subordinated notes. We repaid the senior secured acquisition term loan
in March 2003 with proceeds from our issuance of $300 million of 8 1/2% Senior
Subordinated Notes.

As part of this transaction, El Paso Corporation is required, subject to
specified conditions, to repurchase the Chaco processing plant from us for $77
million in October 2021, and at that time, we will have the right to lease the
plant from El Paso Corporation for a period of ten years with the option to
renew the lease annually thereafter.

In accordance with our procedures for evaluating and valuing material
acquisitions with El Paso Corporation, our Audit and Conflicts Committee engaged
independent financial advisors. Separate financial advisors delivered fairness
opinions for the acquisition of the San Juan assets and the issuance of the
Series C units. Based on these opinions, our Audit and Conflicts Committee and
the full board of directors approved these transactions.

EPN Holding Acquisition

In April 2002, EPN Holding Company, L.P., our wholly-owned subsidiary,
acquired from subsidiaries of El Paso Corporation, midstream assets located in
Texas and New Mexico. The acquired assets, which we refer to as the EPN Holding
assets, include:

- the EPGT Texas intrastate pipeline system;

- the Waha natural gas gathering system and treating plant located in the
Permian Basin region of Texas;

- the Carlsbad natural gas gathering system located in the Permian Basin
region of New Mexico;

- an approximate 42.3 percent non-operating interest in the Indian Basin
natural gas processing and treating facility located in southeastern New
Mexico and price risk management activities associated with the plant;

- a 50 percent undivided interest in the Channel natural gas pipeline
system located along the Gulf coast of Texas;

- the TPC Offshore natural gas pipeline system located off the Gulf coast
of Texas; and

- a leased interest in the Wilson natural gas storage facility located in
Wharton County, Texas.

The $750 million sales price was adjusted for the assumption of $15 million
of working capital related to natural gas imbalances. The net consideration of
$735 million for the EPN Holding assets was comprised of the following (in
millions):

Cash........................................................ $420
Assumed short term indebtedness payable to El Paso
Corporation (none of which is outstanding as of December
31, 2002)................................................. 119
Common units................................................ 6
Sale of our Prince tension leg platform (TLP) and our nine
percent Prince overriding royalty interest................ 190
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$735
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To finance substantially all of the cash consideration related to this
acquisition, EPN Holding entered into a $535 million term loan facility with a
syndicate of commercial banks, of which $375 million has been repaid and the
remaining amount was restructured in October 2002. This term loan facility and
the restructuring are described in more detail in "Management's Discussion and
Analysis of Financial Condition

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and Results of Operations -- Liquidity and Capital Resources" and Item 8,
Financial Statements and Supplementary Data, Note 6.

SEGMENTS

In light of our expectation of acquiring additional natural gas pipeline
and processing assets, effective January 1, 2002, we revised and renamed our
business segments to reflect the change in composition of our operations for all
periods presented, as discussed below. We have segregated our business
activities into four distinct operating segments:

- Natural gas pipelines and plants;

- Oil and NGL logistics;

- Natural gas storage; and

- Platform services.

These segments are strategic business units that provide a variety of
energy related services. For information relating to revenues from external
customers, operating income and total assets of each segment, see Item 8,
Financial Statements and Supplementary Data, Note 14. Each of these segments is
discussed more fully below.

NATURAL GAS PIPELINES AND PLANTS

Natural Gas Pipelines Systems

We own interests in natural gas pipeline systems extending over 15,700
miles, with a combined maximum design capacity (net to our interest) of over
10.3 Bcf/d of natural gas. We own or have interests in gathering systems onshore
in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas including the
San Juan gathering system and the Texas Intrastate system. In addition to our
onshore natural gas pipeline systems, 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.

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The following table and discussions describe our natural gas pipelines, all
of which (other than portions of the Texas Intrastate system) we wholly own and
operate.

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(1) The average throughput reflects 100 percent of the throughput. We acquired
the Texas Intrastate system and the Permian Basin system together with the
other EPN Holding assets in April 2002 from subsidiaries of El Paso
Corporation.

(2) The Texas Intrastate system is comprised of the EPGT Texas intrastate, the
TPC Offshore and the Channel pipeline systems. The Railroad Commission of
Texas regulates the rates of the EPGT Texas and Channel systems. The Federal
Energy Regulatory Commission (FERC) regulates the Section 311 rates of the
EPGT Texas system, the Channel system and EPIA. HIOS is also regulated by
the FERC as an interstate pipeline under the Natural Gas Act.

(3) The average throughput reflects 100 percent of the throughput. We acquired
the San Juan gathering system and the Typhoon natural gas pipeline together
with the other San Juan assets in November 2002 from a subsidiary of El Paso
Corporation. The Typhoon natural gas pipeline was placed in service in
August 2001.

(4) The average throughput reflects 100 percent of the throughput. Prior to
October 2001, we indirectly owned a 50 percent interest in HIOS and East
Breaks. We acquired the remaining 50 percent interest in October 2001 from
subsidiaries of El Paso Corporation.

(5) All capacity measures are on a MMcf/d basis, and net to our interest with
respect to Texas Intrastate.

(6) All average throughput measures are on a MDth/d basis. For the pipelines
described above, one MDth is approximately equivalent to one MMcf.

Texas Intrastate. The Texas Intrastate system, which we acquired in April
2002, consists of the following natural gas pipelines:

- EPGT Texas Intrastate. The EPGT Texas Intrastate natural gas gathering
system is one of the largest intrastate pipeline systems based on miles
of pipe in the United States. It is also the only intrastate pipeline in
Texas that offers transportation and storage services fully unbundled
from marketing services. The system consists of approximately 7,292 miles
of main lines, laterals and gathering lines with an operating capacity
(net to our interest) of 3,725 MMcf/d. The EPGT Texas intrastate system
includes some small pipelines in which we own undivided interests.

- TPC Offshore. TPC Offshore is a natural gas gathering system located in
the coastal waters of south Texas, consisting of 197 miles of
predominantly 8-inch to 20-inch pipelines that gather "rich" natural gas.
The TPC Offshore system includes some smaller pipelines in which we own
undivided interests.

- Channel pipeline system. The Channel pipeline system is an intrastate
natural gas transmission system located along the Gulf coast of Texas,
consisting of 733 miles of predominantly 30-inch pipelines. We own a 50
percent undivided interest in the Channel pipeline system.

San Juan Gathering System. The San Juan natural gas gathering system, which
we acquired in November 2002, is located in the San Juan Basin. The system
consists of approximately 5,300 miles of main lines, laterals and gathering
lines with capacity of over 1.1 Bcf/d. A significant portion of the
rights-of-way underlying the San Juan gathering system on Native American lands
expire in 2005. We believe we will be able to renew these rights-of-way on terms
and conditions that will not materially adversely affect us.

Permian Basin. The Permian Basin system, which we acquired in April 2002,
consists of the following natural gas pipelines:

- Waha Natural Gas Gathering System. The Waha natural gas gathering system
is a natural gas gathering system located in the Permian Basin region of
Texas, and consists of 501 miles of predominantly 8 to 24-inch pipelines.

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- Carlsbad Natural Gas Gathering System. The Carlsbad gathering system is a
natural gas gathering system located in the Permian Basin region of New
Mexico and consists of approximately 842 miles of predominantly 4-inch to
12-inch pipelines.

Viosca Knoll System. The Viosca Knoll system is an offshore natural gas
gathering system that connects the Main Pass, Mississippi Canyon and Viosca
Knoll areas of the Gulf of Mexico with 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.

High Island Offshore System. HIOS, which became a wholly-owned asset in
October 2001 through our acquisition of the remaining 50 percent interest from
subsidiaries of El Paso Corporation, is an offshore natural gas transmission
system that 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. The East Breaks natural gas gathering system, which
became a wholly-owned asset in October 2001 through our acquisition of the
remaining 50 percent interest that we did not already own, 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 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.

Typhoon Natural Gas Pipeline. The Typhoon pipeline, which we acquired in
November 2002, is an offshore gas pipeline that connects the Typhoon field in
the Green Canyon area of the Gulf of Mexico with El Paso Corporation's ANR
Patterson Offshore pipeline system. We intend to integrate this pipeline into
the Marco Polo natural gas pipeline.

El Paso Intrastate-Alabama System. EPIA, which we acquired in March 2000,
is a natural gas pipeline system that serves the coal bed methane producing
regions of Alabama. EPIA provides marketing services through the purchase of
natural gas from regional producers and others, and sale of natural gas to local
distribution companies and others.

EPIA gathering system provides marketing services and, accordingly,
purchases and resells the natural gas it gathers. Several of our other gathering
systems, while not providing marketing services, have some exposure to risks
related to commodity prices. For example, over 95 percent of the volumes handled
by the San Juan gathering system are handled under fee-based arrangements, 80
percent of which are calculated as a percentage of a regional price index for
natural gas. If we do not use hedges or similar arrangements, the financial
results for these assets could be affected by changes in, or the volatility of,
commodity prices. Additionally, the San Juan gathering system provides
aggregating and bundling services for smaller producers, whereby we purchase
natural gas at the wellhead and resell natural gas in the open market at points
along our pipeline. These services account for less than five percent of the
volumes on that system.

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Natural Gas Processing and Treating Facilities

We own interests in five processing and treating plants in Louisiana, New
Mexico, Texas and Colorado with a combined maximum capacity of over 1.5 Bcf/d of
natural gas and 50 MBbls/d of NGL. The following table and discussions describe
our natural gas processing and treating facilities.

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(1) All capacity measures are on a MMcf/d basis. Indian Basin and Coyote are
reflected at 100 percent capacity.

(2) We own a non-operating interest in the Indian Basin plant. The average
utilization rates were calculated with 100 percent of volumes and capacity.

(3) As part of the San Juan assets acquisition in November 2002, we acquired our
interest in Coyote Gas Treating, LLC. The average utilization rates were
calculated with 100 percent of volumes and capacity.

(4) Effective January 2002, Coyote Gas Treating, LLC entered into a five year
operating lease agreement. Under the terms of the lease, Coyote Gas
Treating, LLC receives fixed monthly lease payments of $635 thousand. We no
longer receive volume data from the operator because our proportionate share
of the revenues is now based on the fixed lease payments.

(5) The decrease in Rattlesnake's utilization rate is the result of an expansion
during 2002 which increased the capacity of the plant to 58 MMcf/d from 25
MMcf/d.

The Chaco cryogenic natural gas processing plant is the fifth 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 650 MMcf/d of natural gas and handling up to 50
MBbls/d of NGL. In October 2001, we acquired substantially all of the interests
in the Chaco plant from affiliates of El Paso Corporation. We acquired all
remaining interests in the Chaco plant in November 2002. El Paso Corporation is
required, subject to specific conditions, to repurchase the Chaco plant from us
in 2021 for $77 million, and we will have the option to lease the plant back
from El Paso Corporation for 10 additional years with the option to renew the
lease annually thereafter.

Construction Projects

Medusa Project. We are constructing the $28 million, 37-mile Medusa
natural gas pipeline extension of our Viosca Knoll gathering system with
capacity to handle 160 MMcf/d of natural gas, which is expected to be in service
in the third quarter of 2003. The pipeline is designed and located to gather
production from Murphy Exploration and Production Company's Medusa development
in the Gulf of Mexico. Murphy has dedicated 34,560 acres of property to this
pipeline for the life of the reserves, which means that all natural gas produced
from this acreage will flow through this pipeline. As of December 31, 2002, we
have spent approximately $17.2 million related to this pipeline extension, which
is currently under construction. We expect to receive contributions in aid of
construction from Tennessee Gas Pipeline Company, a subsidiary of El Paso
Corporation, of $2 million for benefits they expect to receive from our
construction of the pipeline

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extension. We expect to fund the remaining project costs through internally
generated funds and borrowings under our credit facility.

Phoenix (formerly known as Red Hawk). We will build and operate a new $63
million pipeline, now known as the Phoenix gathering system, to gather natural
gas production from the Red Hawk Field located in the Garden Banks area of the
Gulf of Mexico. We have entered into related agreements with Kerr-McGee Oil and
Gas Corporation, a wholly owned subsidiary of Kerr-McGee Corporation, and Ocean
Energy, Inc., which each hold a 50-percent working interest in the Red Hawk
Field. Kerr-McGee Oil and Gas Corporation and Ocean Energy, Inc. have dedicated
multiple blocks at and in the proximity of the Red Hawk Field to this pipeline
for the life of the reserves, subject to certain release provisions. The 76-mile
pipeline, capable of transporting up to approximately 450 MMcf/d of natural gas,
will originate in 5,300 feet of water at the Red Hawk Field and connect to the
ANR Pipeline system at Vermillion Block 397. We plan to place the new pipeline
in service during the second quarter of 2004. As of December 31, 2002, we have
spent approximately $0.1 million related to this pipeline, which is in the
development stage. We expect to receive contributions in aid of construction
from ANR Pipeline Company, a subsidiary of El Paso Corporation, of $6.1 million
for benefits they expect to receive from our construction of this pipeline. We
expect to fund the remaining project costs through internally generated funds
and borrowings under our credit facility.

Marco Polo Project. We will construct and own a 75-mile, 18-inch and
20-inch natural gas pipeline to support the Marco Polo TLP. The natural gas
pipeline, with a maximum capacity of 400 MMcf/d, will gather natural gas from
the Marco Polo platform in Green Canyon Block 608 and transport it to the
Typhoon natural gas pipeline in Green Canyon Block 237. We intend to integrate
the Marco Polo natural gas pipeline and Typhoon natural gas pipeline. This
pipeline is expected to be completed and placed in service in the first quarter
of 2004, and is expected to cost $68 million to construct. As of December 31,
2002, we have spent approximately $1.3 million on this pipeline, which is in the
development stage. Additionally, we expect to receive contributions in aid of
construction from ANR Pipeline Company and El Paso Field Services, subsidiaries
of El Paso Corporation, totaling $17.5 million for benefits they anticipate
receiving from our construction of the natural gas pipeline. As of December
2002, we received approximately $2 million from ANR as contributions in aid of
construction of this pipeline. We expect to fund the remaining project costs
through internally generated funds and borrowings under our credit facility.

Markets and Competition

Each of our natural gas pipeline systems is located at or near natural gas
production areas that are served by other pipelines, and 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.

Our gathering and transportation agreements have varying terms. Our
offshore gathering and transportation arrangements tend to have longer terms,
often involving life-of-reserve commitments with both firm and interruptible
components, and our onshore gathering and transportation arrangements generally
have terms from one month to several years. With respect to the San Juan
gathering system, approximately 70 percent of the volume in 2002 is attributable
to three customers, Burlington Resources, Conoco and BP. These contracts expire
in 2008, 2006 and 2006. The following table indicates the percentage revenue
generated by each contract in relation to the indicated denominator for the year
ended December 31, 2002:

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(1) We have assumed twelve months of San Juan revenues in our calculation of the
percentage revenue generated by each customer in order to more accurately
reflect annual results. The revenue reflected in our statement of income
only includes San Juan as of the acquisition date.

For a discussion of our significant customers, see Item 8, Financial
Statements and Supplementary Data, Note 13.

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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. Gathering arrangements are fee-based and, except for
the EPIA and San Juan gathering system fees, generally do not have exposure to
risks associated with changes in commodity prices. However, our financial
results from some of our onshore pipelines, including the EPIA, Permian Basin
and San Juan gathering systems, can be affected by a reduction in, or volatility
of, commodity prices. The EPIA gathering system provides marketing services and,
accordingly, purchases and resells the natural gas it gathers. Several of our
other gathering systems, while not providing marketing services, have some
exposure to risks related to commodity prices. For example, over 95 percent of
the volumes handled by the San Juan gathering system are fee-based arrangements,
80 percent of which are calculated as a percentage of a regional price index for
natural gas. In connection with our November 2002 San Juan assets acquisition,
we terminated our tolling arrangement covering the Chaco plant with a subsidiary
of El Paso Corporation, effectively replacing the fixed fee revenue previously
received by the Chaco plant with actual revenues derived from sales of natural
gas on the open market, which may produce greater volatility in our Chaco plant
revenues. Our revenues would have approximated $0.234/Dth, $0.263/Dth and
$0.206/Dth as compared to $0.134/Dth had we operated the Chaco plant during the
years ended December 31, 2002, 2001 and 2000 under our current arrangement. In
addition, the San Juan gathering system provides aggregating and bundling
services, in which we purchase gas at the wellhead and resell gas in the open
market at points on our system, for some smaller producers, which account for
less than five percent of the volumes on that system. We use hedges from time to
time to mitigate exposure to risks related to commodity prices.

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. Each of the pipeline systems has continuous
inspection and compliance programs designed to keep our facilities in compliance
with pipeline safety and pollution control requirements. We believe that our
pipeline systems are in material compliance with the applicable requirements of
these regulations.

Our Texas intrastate natural gas assets, some of which are classified as
"gas utilities," are regulated by the Railroad Commission of Texas.

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 pipeline
industry has historically been heavily regulated by federal and state
governments, and we cannot predict what further actions FERC, state regulators,
or federal and state legislators may take in the future. We timely filed a
required rate case for our HIOS system on December 31, 2002. The rate filing and
tariff changes are based on HIOS' cost of service, which includes operating
costs, a management fee, and changes to depreciation rates and negative salvage
amortization. HIOS' filing reflects a zero rate base; therefore, a management
fee in place of a return on rate base has been requested. We requested the rates
be effective February 1, 2003, but the FERC suspended the rate increase until
July 1, 2003, subject to refund. The FERC has scheduled a hearing on this matter
commencing November 17, 2003.

The FERC has issued two Notices of Proposed Rulemaking (NOPR) that may
affect our HIOS operations. See Item 8, Financial Statements and Supplementary
Data, Note 10 -- Commitments and Contingencies -- Rates and Regulatory Matters.

EPGT's FERC Section 311 service rates are subject to FERC rate
jurisdiction. In December 1999, EPGT Texas filed a petition with the FERC for
approval of its maximum rates for interstate transportation service. In June
2002, the FERC issued an order that required revisions to EPGT Texas' proposed
maximum rates. The changes ordered by the FERC involve reductions to rate of
return, depreciation rates and revisions to the proposed rate design, including
a requirement to separately state rates for gathering services. FERC also

10

ordered refunds to customers for the difference, if any, between the originally
proposed levels and the revised rates ordered by the FERC. We believe the amount
of any rate refund would be minimal since most transportation services are
discounted from the maximum rate. EPGT Texas has established a reserve for
refunds. In July 2002, EPGT Texas requested rehearing on certain issues raised
by the FERC's order, including the depreciation rates and the requirement to
separately state a gathering rate. EPGT Texas' request for rehearing has been
granted for further consideration and is pending before the FERC.

In July 2002, Falcon Gas Storage, a competitor, also requested late
intervention and rehearing of the order. Falcon asserts that EPGT Texas'
imbalance penalties and terms of service preclude third parties from offering
imbalance management services. Meanwhile in December 2002, EPGT Texas amended
its Statement of Operating Conditions to provide shippers the option of
resolving daily imbalances using a third-party imbalance service provider.
Falcon objected to the changes, complaining that imbalance resolution is the
lowest priority of service. EPGT Texas responded to Falcon's objection and
untimely intervention, repeating its request that Falcon's intervention be
dismissed.

In December 2002, EPGT Texas requested FERC approval of market-based rates
for interstate gas storage services performed at its Wilson storage facility.
The filing was in compliance with a requirement to rejustify its existing rates
or request new rates by December 20, 2002. Falcon has also intervened in this
filing. This matter is pending before the FERC.

Environmental

Our natural gas pipelines and plants are subject to various safety and
environmental statutes, including: the Natural Gas Act, the Natural Gas Policy
Act, the Outer Continental Shelf Act, the Hazardous Materials Transportation
Act, the Hazardous Liquid Pipeline Safety Act, the Resource Conservation and
Recovery Act, the Comprehensive Environmental Response, Compensation and
Liability Act, the Clean Air Act, the Federal Water Pollution Control Act, the
Endangered Species Act, the Occupational Safety and Health Act, the Emergency
Planning and Community Right-to-Know Act and similar state statutes. We expect
to make capital expenditures for environmental matters of approximately $10
million in the aggregate for the years 2003 through 2007, primarily to comply
with clean air regulations. For a discussion of environmental regulations, see
Environmental-Specific Regulations.

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 sea water. Our HIOS and Viosca Knoll
natural gas 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 or
natural gas stream at the source of production and corrosion control.
Furthermore, the integrity of our onshore pipelines is subject to on-going
integrity assessment and evaluation pursuant to the Pipeline Integrity
Management Plan filed with the Railroad Commission of Texas and revised from
time to time. The Pipeline Integrity Management Plan identifies all pipelines
covered by the plan, establishes a priority ranking for performing the integrity
assessment of pipeline segments of each pipeline system and makes an assessment
of pipeline integrity using methods such as in-line inspection, pressure
testing, direct assessment or other technology or assessment methodology. This
integrity management program is reassessed and refined as necessary on at least
an annual basis by qualified personnel.

Our processing and treating facilities are manned on a continuous basis by
personnel who are responsible for maintenance and operations. The maintenance of
the facilities is an ongoing process, which is performed based on hours of
operation, oil analysis and vibration monitoring. Shutdown of our processing and
treating facilities is not required for regular maintenance activity. Coyote and
Indian Basin are operated and maintained by third parties that own interests in
those systems.

11

OIL AND NGL LOGISTICS

NGL Transportation and Fractionation Facilities

EPN Texas. In February 2001, we acquired EPN Texas from subsidiaries of El
Paso Corporation. EPN Texas includes more than 500 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 NGL from various processing
plants to the Shoup Plant, located in Corpus Christi, the largest of EPN Texas'
three fractionators. The system also includes 161 miles of pipelines that
deliver fractionated products such as ethane, propane, butane and natural
gasoline 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. However, the average utilization rate for EPN Texas
for years ended December 31, 2002, 2001 and 2000 was 74 percent, 73 percent and
89 percent.

Additional Texas NGL Facilities. As part of the November 2002 San Juan
assets acquisition, we acquired from subsidiaries of El Paso Corporation
additional NGL assets located in Texas. These assets include over 500 miles of
NGL pipelines that transport propane and butane to refineries and petrochemical
users from Corpus Christi to Houston and within the Houston-Texas City area.
These assets also provide access to the Mont Belvieu NGL markets. Portions of
these NGL assets are shut-in pending refurbishment and expansion, which is
expected to be completed by May 2003. These NGL assets also include the Almeda
fractionator, which has fractionation capacity of 24 MBbls/d. The average
utilization rate for the Almeda fractionator for the year ended December 31,
2002 was less than two percent due to the portions that were shut-in pending
refurbishment and expansion. The average utilization rate for the Almeda
fractionator for years ended December 31, 2001 and 2000 was 32 percent and 26
percent.

Offshore Oil Pipeline Systems

We own interests in three offshore oil pipeline systems, which extend over
340 miles and have a combined capacity of approximately 635 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 oil-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.

The following table and discussions describe our offshore oil pipelines.

- ---------------

(1) The average throughput reflects 100 percent of the throughput. We acquired
the Typhoon oil pipeline together with the other San Juan assets in November
2002, from subsidiaries of El Paso Corporation.

(2) All capacity measures are on a MBbls/d basis, and with respect to Poseidon,
include 100 percent of the design capacity. Poseidon and Allegheny's
capacity measures can be achieved with the addition of pumps and use of
friction reducers.

(3) All average throughput measures are on a MBbls/d basis, and with respect to
Poseidon, net to our interests.

12

Poseidon System. Poseidon is a major offshore sour crude oil pipeline
system that we built in response to the increased demand for additional sour
crude oil pipeline capacity in the central Gulf of Mexico. The Poseidon system
is owned by Poseidon Oil Pipeline Company, L.L.C., in which we own a 36 percent
membership interest. We began operating the Poseidon system in January 2001. The
Poseidon system consists of:

- 117 miles of 16 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

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

Poseidon Oil Pipeline Company, L.L.C. is party to a revolving credit
agreement that requires it to maintain a debt service reserve of two quarters'
interest. Other than that debt service reserve amount and any other reserve
amounts agreed upon by more than a 72 percent interest of Poseidon's members,
Poseidon distributes monthly all of its available cash to its members. Poseidon
is managed by a management committee consisting of representatives from each of
its members.

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. Oil production from the Allegheny field
is committed to this system.

Typhoon Oil Pipeline. The Typhoon oil pipeline is an offshore crude oil
pipeline consisting of 16 miles of 12-inch diameter pipeline that connects the
Typhoon field discovery in the Green Canyon area of the Gulf of Mexico to the
Shell Boxer platform, a delivery point into the Poseidon pipeline.

NGL storage

Hattiesburg Propane Storage. In January 2002, we acquired a 3.3 MMBbl
propane storage business and leaching operation located in Hattiesburg,
Mississippi from Suburban Propane, L.P. for approximately $8 million. As part of
that transaction, we entered into a long-term propane storage agreement with
Suburban Propane, L.P. for a portion of the acquired propane storage capacity.

Anse La Butte NGL Storage. In December 2001, we acquired Anse La Butte, a
3.2 MMBbl 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 with El Paso Field Services, a subsidiary of El Paso
Corporation, for a significant portion of the storage capacity.

Texas Leased NGL Storage Facilities. As part of the November 2002 San Juan
assets acquisition, we acquired leases for three NGL storage facilities in Texas
with aggregate capacity of approximately 18.1 MMBbls. The leases covering these
facilities expire in 2006 and 2012.

Construction Projects

Marco Polo Project. We will construct and own a 36-mile, 14-inch oil
pipeline to support the Marco Polo TLP. The oil pipeline will gather oil from
the Marco Polo platform to our Allegheny pipeline in Green Canyon Block 164 with
a maximum capacity of 120 MBbls/d. This pipeline is expected to be completed and
placed in service in the first quarter of 2004, and is expected to cost $28
million to construct. As of December 31, 2002, we have spent approximately $1.3
million on this pipeline, which is in the development stage. We expect to fund
the remaining project costs through internally generated funds and borrowings
under our credit facility.

13

Cameron Highway. In February 2002, we announced that we will build and
operate the $458 million, 390-mile Cameron Highway oil pipeline with capacity of
500 MBbls/d, which is expected to be in service by the third quarter of 2004,
and will provide producers with access to onshore delivery points in Texas. BP
p.l.c., BHP Billiton and Unocal have dedicated 86,400 acres of property to this
pipeline for the life of the reserves, including the acreage underlying their
ownership interests in the Holstein, Mad Dog and Atlantis developments in the
deeper water regions of the Gulf of Mexico. In October 2002, we entered into a
non-binding letter of intent with Valero Energy Corporation under which Valero
would acquire a 50 percent interest in the entity we form to construct, install
and own this pipeline, which we will operate. The formation of this joint
venture is subject to specific conditions set forth in the letter of intent,
including negotiating and executing definitive documentation and obtaining
mutually acceptable financing. We are contractually committed to the Cameron
Highway project whether or not we obtain a partner or any other financing. We
expect that a majority of the costs of this project will be funded through
project financing, which we are currently negotiating. However, due to the
volatility in the capital markets, it is conceivable that we could have to
access capital from other sources, including cash from operations. We estimate
that the majority of the capital outlay for the project will occur in 2003 and
2004. As of December 31, 2002, we have spent approximately $14.6 million related
to this pipeline, which is in the development stage.

Markets and Competition

A base amount of utilization, 60% to 70%, of our Texas fractionation
facilities will occur because most of the natural gas in south Texas must be
processed in order to meet downstream pipeline specifications; however, full
utilization of our fractionation facilities occurs only when the natural gas
producer can receive more net proceeds by processing -- extracting and selling
the NGL components contained in the raw natural gas -- than they would receive
by merely selling the unprocessed natural gas stream. The spread between natural
gas and NGL varies from time to time depending on a complex number of factors
including (1) natural gas supply, demand and storage inventories, (2) NGL
supply, demand and storage inventories and (3) crude oil prices. Given these
intricate factors, the spread between natural gas and NGL prices exhibits weekly
and monthly volatility. If a gas producer determines that this spread is too
low, that producer will choose to use our facilities at only the minimum level
required to meet downstream pipeline gas quality specifications. Regardless of
the elections made by the producers, our fractionation facilities would continue
to be operated, but at lower utilization, and we will continue to incur
operating costs regardless of the utilization level.

Our NGL pipelines provide the sole outlet for natural gas liquids from the
seven natural gas processing plants in south Texas owned by subsidiaries of El
Paso Corporation. As is the case for the Texas fractionation facilities, the
volume of NGL carried by these pipelines is dependent upon the volume of natural
gas available for processing and the economics of extraction of natural gas
liquids viewed by the natural gas producers. The principal competition for our
pipelines that carry NGL from the Texas fractionation facilities include
pipeline systems owned by petrochemical companies and other midstream entities.
While the petrochemical companies may use their pipeline systems to carry NGL
for third parties, their primary use of these assets are to secure hydrocarbon
feedstocks for their own plant complexes along the Texas Gulf Coast. In general,
our NGL pipelines are well positioned to deliver products such as propane and
butane from our Texas fractionation facilities to key end-use markets such as
refiners and petrochemical facilities along the Texas Gulf Coast.

In connection with our February 2001 acquisition of EPN Texas, we entered
into a 20-year fee-based transportation and fractionation agreement and
dedicated 100 percent of the capacity of our fractionation facilities to a
subsidiary of El Paso Corporation. In this agreement, all of the NGL 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 NGL 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
NGL.

14

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 pipeline systems
are attributed to production from reserves committed under long-term contracts
for the productive life of the relevant field, typically involving both firm and
interruptible components. 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. Our oil
systems are not subject to regulatory rate-making authority, and 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.
Generally, we receive a price per barrel of oil or water handled.

For a discussion of our significant customers, see Item 8, Financial
Statements and Supplementary Data, Note 13.

Regulatory Environment

Our offshore oil pipeline systems are subject to federal 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. Each of the oil pipeline systems has continuing programs of
inspection and compliance designed to keep all of our facilities in compliance
with pipeline safety and pollution control requirements. We believe that our oil
pipeline systems are in material compliance with the applicable requirements of
these regulations.

In addition, our NGL assets are subject to extensive federal, state, and
local laws and regulations governing environmental quality and pollution
control. These assets have a continuing program of inspection designed to keep
all of our assets in compliance with pollution control and pipeline safety
requirements. We believe that these NGL assets are in compliance with the
applicable requirements of these regulations. Our NGL pipelines in Texas, some
of which we classified as common carriers, are regulated by the Texas Railroad
commission.

Environmental

Our oil and natural gas logistics operations are subject to various safety
and environmental statutes, including: the Outer Continental Shelf Act, the
Hazardous Liquid Pipeline Safety Act, the Resource Conservation and Recovery
Act, the Comprehensive Environmental Response, Compensation and Liability Act,
the Clean Air Act, the Federal Water Pollution Control Act, the Oil Pollution
Act of 1990, the Endangered Species Act, the Occupational Safety and Health Act,
the Emergency Planning and Community Right-to-Know Act and similar state
statutes. For a discussion of environmental regulations, see
Environmental -- Specific Regulations.

Maintenance

Each of our pipeline systems, our fractionation facilities and our
processing facilities require regular maintenance. The interior of the EPN
Texas, Allegheny, Typhoon and Poseidon pipelines is maintained through the
regular cleaning of the line of liquids that collect in the pipelines. 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.
15

NATURAL GAS STORAGE

We own the Petal and Hattiesburg salt dome natural gas storage facilities
located in Mississippi, which are strategically situated to serve the Northeast,
Mid-Atlantic and Southeast natural gas markets. In June 2002, we completed a 8.9
Bcf (6.3 Bcf working capacity) expansion of our Petal facility, including a
withdrawal facility and a 20,000 horsepower compression station and a 60-mile
takeaway pipeline, including a 9,000 horsepower compression station. These two
facilities have a combined current working capacity of 13.5 Bcf, and are capable
of delivering in excess of 1.2 Bcf/d of natural gas into five interstate
pipeline systems: Transco, Destin Pipeline, Gulf South Pipeline, Southern
Natural Gas Pipeline and Tennessee Gas Pipeline. Each of these facilities is
capable of making deliveries at the high rates necessary to satisfy peak
requirements in the electric generation industry. As a result of the successful
completion of our Petal expansion and a general increase in the storage
business, we have experienced interest from third parties in acquiring an
ownership interest in our Petal and Hattiesburg facilities. We are evaluating
all our options relating to these facilities, including discussions with various
third parties to evaluate their level of interest. At this time, we cannot
predict what changes, if any, in our ownership of these facilities will result
from our evaluation.

The Hattiesburg facility is outside of Hattiesburg, Mississippi, and
consists of three high-deliverability natural gas storage caverns. The facility
has an injection capacity in excess of 175 MMcf/d of natural gas and a
withdrawal capacity in excess of 400 MMcf/d of natural gas. The Hattiesburg
capacity is currently fully subscribed, primarily with eleven long-term
contracts expiring between 2005 and 2006.

The Petal facility is less than one mile from the Hattiesburg facility and
consists of two high-deliverability natural gas storage caverns. The Petal
facility has an injection capacity in excess of 430 MMcf/d of natural gas and a
withdrawal capacity of 865 MMcf/d of natural gas. The Petal capacity is 91
percent subscribed, with 7.0 Bcf 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, and 1.65 Bcf subscribed to BP Energy Company.

The ability of the facilities to handle these 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
favorable natural gas prices and also provide customers the opportunity to
quickly respond in situations where they have natural gas imbalance issues on
pipelines connected to the storage facility. 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.

In addition to our Petal and Hattiesburg facilities, we have the exclusive
right to use the Wilson natural gas storage facility under an operating lease
that expires in January 2008 and, subject to certain conditions, has one or more
optional renewal periods of five years each at fair market rent at the time of
renewal. The Wilson facility is comprised of 62 acres, in Wharton County, Texas,
and consists of four caverns with a working gas
16

capacity of 6.4 Bcf. The facility has an injection capacity of 150 to 360 MMcf/d
of natural gas and a maximum withdrawal capacity of 800 MMcf/d of natural gas.
The Wilson capacity is currently 91 percent subscribed with long-term contracts
expiring between 2006 and 2007.

Markets and Competition

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 capacity relating to the Petal facility is dedicated under a
20-year, fixed-fee contract. 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, 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.

For a discussion of our significant customers see Item 8, Financial
Statements and Supplementary Data, Note 13.

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 rate 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 public
convenience and necessity that permits us to charge market-based rates. The
natural gas pipeline 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 June 2002, the Petal facility filed with the FERC a certificate
application to add additional gas storage and injection capacity to Petal's
storage system. The filing included a new storage cavern with a working gas
storage capacity of 5 Bcf, the conversion and enlargement of an existing
subsurface brine storage cavern to a gas storage cavern with a working capacity
of up to 3 Bcf and related surface facilities, natural gas, water and brine
transmission lines. In February 2003, the FERC approved the facilities proposed
by Petal.

The FERC has issued two NOPRs that may affect our Petal operations. See
Item 8, Financial Statements and Supplementary Data, Note 10.

The Wilson natural gas storage facility is regulated by the Railroad
Commission of Texas and its Section 311 services are regulated by the FERC.

Environmental

Our natural gas storage operations are subject to various safety and
environmental statutes, including: the Natural Gas Act, the Natural Gas Policy
Act, the Hazardous Materials Transportation Act, the Resource Conservation and
Recovery Act, the Comprehensive Environmental Response, Compensation and
Liability Act, the Clean Air Act, the Clean Water Act, the Endangered Species
Act, the Occupational Safety and
17

Health Act, the Emergency Planning and Community Right-to-Know Act, and similar
state statutes. For a discussion of environmental regulation, see
Environmental -- Specific Regulations.

Maintenance

Our storage facilities are manned on a continuous basis by personnel
responsible for maintenance and operations. Maintenance of the surface
facilities is an ongoing process and is performed per equipment manufacturers'
recommendations, established preventative maintenance schedules or as required
by operating conditions. Maintenance of the Hattiesburg and Petal storage
caverns includes a mechanical integrity test performed every five years as
required by the Mississippi State Oil and Gas Board. Maintenance of the Wilson
storage caverns and brine water disposal caverns includes a mechanical integrity
test performed every five years for the storage caverns and every three years
for the disposal caverns, as constituted by the Railroad Commission of Texas.

PLATFORM SERVICES

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 hub platforms in the Gulf
of Mexico, including the completion of the Falcon Nest fixed leg platform which
we brought on line in March 2003. 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 for, and attract new volumes into,
our offshore pipeline systems. The following table and discussions describe our
platforms.

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(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.

East Cameron 373. The East Cameron 373 platform is located at the south end
of the central leg of Shell's Stingray 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, 200 and 201 production and the
East Cameron Blocks 374 and 380 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

18

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 and Walter Oil and Gas' Viosca Knoll 862 lease.

Ship Shoal 331. The Ship Shoal 331 platform is a production facility
located approximately 75 miles off the coast of Louisiana. Maritech Resources,
Inc. 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 system and serves as the western-most
termination point of the Poseidon system. The platform serves as a base for
landing deepwater production from Newfield Exploration Inc.'s Garden Banks Block
161 development, LLOG Exploration Offshore's Garden Banks Block 205 lease and
Amerada Hess Corporation's Garden Banks Block 158 lease. 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 117 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.

Falcon Nest. In April 2002, we entered into an agreement to construct and
own the $53 million Falcon Nest fixed-leg platform, together with related
pipelines. Falcon Nest will process natural gas from Pioneer Natural Resources
Company's and Mariner Energy, Inc.'s Falcon Field discovery in the Gulf of
Mexico. The platform and related pipelines were installed at Mustang Island
Block 103 in the northwest portion of the Falcon Field and commissioned in the
first quarter of 2003 and natural gas began flowing to the platform from the
Falcon Field in March 2003. Pioneer and Mariner have dedicated 69,120 acres of
property, including acreage underlying their Falcon Field discovery, to this
platform for the life of the reserves. As of December 31, 2002, we have spent
approximately $31.0 million on this project. We expect to fund the remaining
project costs through internally generated funds and borrowings under our credit
facility.

Construction Projects

Marco Polo Project. We are constructing the Marco Polo TLP with a maximum
handling capacity of 120 MBbls/d of oil and 300 MMcf/d of natural gas. This TLP,
which we expect to be in service in the fourth quarter of 2003, was designed and
located to process oil and natural gas from Anadarko Petroleum Corporation's
Marco Polo Field discovery in the Gulf of Mexico. Anadarko has dedicated 69,120
acres of property to this TLP, including the acreage underlying their Marco Polo
Field discovery, for the life of the reserves. Anadarko will have firm capacity
of 50 MBbls/d of oil and 150 MMcf/d of natural 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. This TLP will be owned
by Deepwater Gateway, L.L.C., our 50 percent owned joint venture with Cal Dive
International, Inc., a leading energy services company specializing in subsea
construction and well operations. We will operate Deepwater Gateway and the
Marco Polo TLP will be operated by Anadarko. The total cost of the project is
estimated to be $206 million, or approximately $103 million for our share. As of
December 31, 2002, Deepwater Gateway has spent approximately $108.1 million on
this TLP.

In August 2002, Deepwater Gateway obtained a $155 million project finance
loan at a variable interest rate from a group of commercial lenders to finance a
substantial portion of the cost to construct the Marco Polo TLP and related
facilities. The loan is collateralized by substantially all of Deepwater
Gateway's assets. If Deepwater Gateway defaults on its payment obligations under
the loan, we would be required to pay to the lenders all distributions we or any
of our subsidiaries have received from Deepwater Gateway up to $22.5 million. As
of December 31, 2002, Deepwater Gateway had $27 million outstanding under the
project finance loan and has not paid us, our joint venture partner or any of
our subsidiaries any distributions.

As of December 31, 2002, we have contributed $33 million, as our 50 percent
share, to Deepwater Gateway, which amount satisfies our funding requirement
related to the Marco Polo TLP. We expect that the remaining cost associated with
the Marco Polo TLP will be funded through the $155 million project finance

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loan. This project finance loan will mature in July 2004 unless construction is
completed before that time and Deepwater Gateway meets other specified
conditions, in which case the project finance loan will convert into a term loan
with a final maturity date of July 2009. The loan agreement requires Deepwater
Gateway to maintain a debt service reserve equal to six months' interest. Other
than the debt service reserve and any other reserve amounts agreed upon by more
than 66.7 percent majority interest of Deepwater Gateway's members, Deepwater
Gateway will (after the project finance loan is either repaid or converted into
a term loan) distribute any available cash to its members quarterly. Deepwater
Gateway is not currently generating operating income or cash flow. Deepwater
Gateway is managed by a management committee consisting of representatives from
each of its members.

Markets and Competition

Our platforms are subject to similar competitive factors as our 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.

OTHER

Currently, we own interests in five 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 sold to
various third parties and subsidiaries of El Paso Corporation. We intend to
continue to concentrate on fee-based operations that traditionally provide more
stable cash flow and de-emphasize our commodity-based activities, including
exiting the oil and natural gas production business by not acquiring additional
properties.

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Producing Properties

The following table sets forth information regarding our producing
properties as of December 31, 2002.

- ---------------

(1) We own a 2.5 percent overriding interest in Garden Banks Block 73, which
began producing in mid-2000 and continued producing through September 2001.
The owner plans to plug and abandon this well in 2003.

(2) 25 percent of our 100 percent 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, 2002, the unpaid portion of the production
payment obligation totaled $9.3 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.

Acreage and Wells. The following table sets forth our developed and
undeveloped oil and natural gas acreage as of December 31, 2002. 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 table refer to the number of acres
in which a working interest is owned directly by us. The number of net acres is
our fractional ownership of the working interest in the gross acres.

Our gross and net ownership in producing wells in which a working interest
is owned directly by us at December 31, 2002, 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 we plan to spend
$2.6 million in the next three years to develop our proved undeveloped reserves.

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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. Net oil and natural gas production
volumes from our overriding royalty interest in the Prince Field were
approximately 50 MBbls and 37 MMcf in 2002 and 37 MBbls and 32 MMcf in 2001.
We did not have any production volumes from our overriding royalty interest
in the Prince Field in 2000. Average realized oil and natural gas sales
prices for 2000 were impacted by hedging activities. Excluding our hedging
activities, our average realized sales price would have been $28.12 for oil
and $3.91 for natural gas in 2000.

(2) The components of average segment realized production costs, which consist
of production expenses per unit of oil or natural gas produced, may vary
substantially among wells depending on the methods of recovery employed and
other factors. Our production expenses include third party transportation
expenses, maintenance and repair, labor and utilities costs, as well as the
cost of platform access fees paid by our oil and natural gas subsidiary,
included in our oil and natural gas production segment, to subsidiaries
included in our platforms segment. These platform access fees are eliminated
in our consolidated financial statements. For the year 2002, these platform
access fees were approximately $6.8 million and for each of the years 2001
and 2000, these platform access fees were approximately $10 million. On a
consolidated basis our average realized production costs were as follows:

- ---------------

(1) The increase in per unit production costs from year to year was a result of
production declines coupled with higher offshore oil and natural gas field
servicing and direct 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.

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;

22

- using and restoring the surface 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.

Environmental

Our production and development operations are subject to various safety and
environmental statutes, including: the Outer Continental Shelf Act, the
Hazardous Materials Transportation Act, the Resource Conservation and Recovery
Act, the Comprehensive Environmental Response, Compensation and Liability Act,
the Clean Air Act, the Federal Water Pollution Control Act, the Oil Pollution
Act of 1990, the Endangered Species Act, the Occupational Safety and Health Act
and similar state statutes. For a discussion of environmental regulations, see
Environmental -- Specific Regulations.

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.

ENVIRONMENTAL

GENERAL

We are subject to extensive federal, state and local laws and regulations
governing environmental quality and pollution control. These laws and
regulations require us to remove or remedy the effect on the environment of the
disposal or release of specified substances at current and former operating
sites.

It is possible that new information or future developments could require us
to reassess our potential exposure related to environmental matters. We may
incur significant costs and liabilities in order to comply with existing
environmental laws and regulations. It is also possible that other developments,
such as increasingly strict environmental laws, regulations and claims for
damages to property, employees, other persons and the environment resulting from
current or past operations, could result in substantial costs and liabilities in
the future. As this information becomes available, or other relevant
developments occur, we will make accruals accordingly. A description of our
environmental matters is included in Item 8, Financial Statements and
Supplementary Data, Note 10.

SPECIFIC REGULATIONS

Pipelines. Several federal and state environmental statutes and
regulations may pertain specifically to the operations of our pipelines. The
Hazardous Materials Transportation Act regulates materials capable of posing an
unreasonable risk to health, safety and property when transported in commerce.
The Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act
authorize the development and enforcement of regulations governing pipeline
transportation of natural gas and NGL. Although federal

23

jurisdiction is exclusive over regulated pipelines, the statutes allow states to
impose additional requirements for intrastate lines if compatible with federal
programs. New Mexico, Texas and Louisiana have developed regulatory programs
that parallel the federal program for the transportation of natural gas and NGL
by pipelines.

Solid Waste. The operations of our pipelines and plants may generate both
hazardous and nonhazardous solid wastes that are subject to the requirements of
the Federal Solid Waste Disposal Act, Resource Conservation and Recovery Act, or
RCRA, and their regulations, and similar state statutes and regulations.
Further, it is possible that some wastes that are currently classified as
nonhazardous, via exemption or otherwise, perhaps including wastes currently
generated during pipeline operations, may, in the future, be designated as
"hazardous wastes," which would then be subject to more rigorous and costly
treatment, storage, transportation, and disposal requirements. Such changes in
the regulations may result in additional expenditures or operating expenses by
us.

Hazardous Substances. The Comprehensive Environmental Response,
Compensation and Liability Act, or CERCLA, and comparable state statutes, also
known as "Superfund" laws, impose liability, without regard to fault or the
legality of the original conduct, on certain classes of persons that cause or
contribute to the release of a "hazardous substance" into the environment. These
persons include the current owner or operator of a site, the past owner or
operator of a site, and companies that transport, dispose of, or arrange for the
disposal of the hazardous substances found at the site. CERCLA also authorizes
the EPA or state agency, and in some cases, third parties, to take actions in
response to threats to the public health or the environment and to seek to
recover from the responsible classes of persons the costs they incur. Despite
the "petroleum exclusion" of CERCLA Section 101(14) that currently encompasses
natural gas, we may nonetheless handle "hazardous substances" within the meaning
of CERCLA, or similar state statutes, in the course of our ordinary operations.

Air. Our operations may be subject to the Clean Air Act, or CAA, and
similar state statutes. The 1990 CAA amendments and accompanying regulations,
state or federal, may impose certain pollution control requirements with respect
to air emissions from operations, particularly in instances where a company
constructs a new facility or modifies an existing facility. We may also be
required to incur certain capital expenditures in the next several years
estimated to be approximately $10 million in aggregate for the years 2003
through 2007 for air pollution control equipment in connection with maintaining
or obtaining operating permits and approvals addressing other air
emission-related issues. However, we do not believe our operations will be
materially adversely affected by any such requirements.

Water. The Federal Water Pollution Control Act, or FWPCA or Clean Water
Act, imposes strict controls against the unauthorized discharge of pollutants,
including produced waters and other oil and natural gas wastes into navigable
waters. The FWPCA provides for civil and criminal penalties for any unauthorized
discharges of oil and other substances and, along with the Oil Pollution Act of
1990, or OPA, imposes substantial potential liability for the costs of oil or
hazardous substance removal, remediation and damages. Similarly, the OPA imposes
liability for the discharge of oil into or upon navigable waters or adjoining
shorelines. State laws for the control of water pollution also provide varying
civil and criminal penalties and liabilities in the case of an unauthorized
discharge of pollutants into state waters.

Communication of Hazards. The Occupational Safety and Health Act, the
Emergency Planning and Community Right-to-Know Act and comparable state statutes
require those entities that operate facilities for us to organize and
disseminate information to employees, state and local organizations, and the
public about the hazardous materials used in our operations and our emergency
planning.

EMPLOYEES

Neither we nor El Paso Energy Partners Company, our general partner, has
any employees. 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 behalf of, us, including expenses incurred
by us under the general and administrative services agreement.

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AVAILABLE INFORMATION

Our website is http://www.elpasopartners.com. We make available, free of
charge on or through our website, our annual, quarterly and current reports, and
any amendments to those reports, as soon as is reasonably possible after these
reports are filed with the Securities and Exchange Commission (SEC). Information
contained on our website is not part of this report.

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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.

Substantially all of our assets and the assets of our subsidiaries (other
than our unrestricted subsidiaries, Matagorda Island Area Gathering System,
Arizona Gas Storage, L.L.C. and EPN Arizona Gas, L.L.C.), together with our
general partner's general and administrative services agreement, are pledged as
collateral under our credit facility, the EPN Holding term credit facility and
our senior secured acquisition term loan. We repaid the senior secured
acquisition term loan in March 2003 with proceeds from an issuance of $300
million 8 1/2% Senior Subordinated Notes, which are unsecured obligations of
ours and our guarantor subsidiaries. In addition, our Poseidon and Deepwater
Gateway joint ventures currently have credit facilities or credit agreements
under which substantially all of their assets are pledged. For a discussion of
our credit facilities, see Item 8, Financial Statements and Supplementary Data,
Note 6.

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 March 24, 2003, there were 726 holders of record of common
units and the closing price on the NYSE for common units was $31.10 per unit.

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

In January 2003, we declared a quarterly distribution of $0.6750 per common
unit which was paid on February 15, 2003, to unitholders of record on January
31, 2003. Our quarterly distribution rate represents an annual distribution rate
of $2.70 per unit, up $0.20 compared to the annual rate of $2.50 declared in the
fourth quarter of 2001.

CASH DISTRIBUTIONS

We make quarterly distributions of 100 percent of our available cash, as
defined in our 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,
2002, we paid $111.8 million in distributions to our common unitholders,
including El Paso Corporation, and $42.7 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 Series C units in November
2002. The issuance of these units may effect our payment of distributions. See
Series B Preference Units and Series C Units below for a discussion of these
units. Also, see Item 8, Financial Statements and Supplementary Data, Note 8,
for a discussion relating to cash distributions.

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RECENT OFFERINGS OF COMMON UNITS

In April 2002, we completed simultaneous offerings of 4,083,938 common
units, which included a public offering of 3,000,000 common units and a private
offering at the same unit price of 1,083,938 common units to our general partner
(pursuant to our general partner's anti-dilution right under our partnership
agreement) which was an exempt transaction under Section 4(2) of the Securities
Act of 1933 as a transaction not involving a public offering. We used the net
cash proceeds of approximately $149 million to reduce indebtedness under the EPN
Holding term credit facility. Also in April 2002, we issued in a private
offering 159,497 common units at the then-current market price of $37.74 per
unit to a subsidiary of El Paso Corporation as partial consideration for our
acquisition of the EPN Holding assets. In addition, our general partner
contributed approximately $0.6 million in cash to us in order to maintain its
one percent capital account balance.

In October 2001, we completed simultaneous 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
(pursuant to our general partner's anti-dilution right under our partnership
agreement) which was an exempt transaction under Section 4(2) of the Securities
Act of 1933 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 170,000
cumulative redeemable Series B preference units, with a value of $170 million,
in exchange for the Petal and Hattiesburg 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, 2002, the liquidation value of the outstanding
Series B preference units was approximately $158 million.

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SERIES C UNITS

In N