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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(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) 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.

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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.

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

(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

19

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.

20

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.

21

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.

24

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.

27

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 November 2002, we issued to a subsidiary of El Paso Corporation
10,937,500 of Series C units at a price of $32 per unit, $350 million in the
aggregate, as part of our consideration paid for the San Juan assets. The
issuance of the Series C units was an exempt transaction under Section 4(2) of
the Securities Act of 1933 as a transaction not involving a public offering. The
Series C units are similar to our existing common units, except that the Series
C units are non-voting. After April 30, 2003, the holder of Series C units will
have the right to cause us to propose a vote of our common unitholders as to
whether the Series C units should be converted into common units. If our common
unitholders approve the conversion, then each Series C unit will convert into a
common unit. If our common unitholders do not approve the conversion within 120
days after the vote is requested, then the distribution rate for the Series C
units will increase to 105 percent of the common unit distribution rate in
effect from time to time. Thereafter, the Series C unit distribution rate can
increase on April 30, 2004, to 110 percent of the common unit distribution rate
and on April 30, 2005, to 115 percent of the common unit distribution rate.
Since all of the outstanding Series C units are owned by one party, there is no
market for those units.

EQUITY COMPENSATION PLANS

Refer to the information included in Item 12, Security Ownership of
Management, regarding securities authorized for issuance under equity
compensation plans.

29

ITEM 6. SELECTED FINANCIAL DATA

- ----------

(1) Our operating results and financial position reflect the acquisitions of:
- the San Juan assets in November 2002;
- the EPN Holding assets in April 2002;
- the Chaco plant and the remaining 50 percent interest we did not already
own in Deepwater Holdings in October 2001;
- EPN Texas in February 2001;
- the Petal and Hattiesburg natural gas storage facilities in August 2000;
- EPIA in March 2000; and
- an additional 49 percent interest in Viosca Knoll in June 1999.
The acquisitions were accounted for as purchases and therefore operating
results of these acquired entities are included in our results prospectively
from the purchase date. In addition, operating results and financial position
reflect the sale of our and Deepwater Holdings' interests in several offshore
Gulf of Mexico assets in January and April of 2001 as a result of an FTC
order related to El Paso Corporation's merger with The Coastal Corporation.
(2) As a result of the disposition of our Prince assets in April 2002, the
results of operations for these assets have been accounted for as
discontinued operations and their related revenue has been excluded from
operating revenues from their in-service date of September 2001 to their
disposal date of April 2002. Operating revenues for 1999 and 1998 have been
restated to exclude earnings from unconsolidated affiliates.
(3)Reflects our 1999 adoption of a preferable accounting method for allocating
partnership income to our general partner and our preference and common
unitholders. We changed our method of allocating net income to our partners'
capital accounts from a method where we allocated income based on percentage
ownership and proportionate share of cash distributions, to a method where
income is allocated to the partners based upon the change from period to
period in their respective claims on our book value capital. We believe that
the new income allocation method is preferable because it more accurately
reflects the income allocation provisions called for under the partnership
agreement and the resulting partners' capital accounts are more reflective of
a partner's claim on our book value capital at each period end. This change
in accounting had no impact on our consolidated net income or our
consolidated total partners' capital for any period presented. The impact of
this change in accounting has been recorded as a cumulative effect adjustment
in our income allocation for the year ended December 31, 1999. The effect of
adopting this change in accounting, excluding the cumulative adjustment, was
to reduce basic and diluted net income per limited partner unit by $0.33 for
the year ended December 31, 1999.
(4)In October 2000, all publicly held preference units were converted into
common units or redeemed.
(5)The increase in 2002 reflects:
- $160 million EPN Holding term credit facility;
- $160 million senior secured term loan; and
- $237.5 million senior secured acquisition term loan.
(6)The balance in 2001 and 2000 relates to a project finance loan to build the
Prince TLP in the Prince Field. With the completion of the Prince TLP, we
converted the project finance loan to a limited recourse loan in December
2001. In connection with the EPN Holding asset acquisition, we repaid this
loan in full in April 2002.

30

(7)The increase in 2002 reflects the issuance of our $200 million 10 5/8% Senior
Subordinated Notes in November 2002 and the issuance of our $230 million
8 1/2% Senior Subordinated Notes in May 2002. The increase in 2001 reflects
the issuance of our $250 million 8 1/2% Senior Subordinated Notes in May
2001. The increase in 1999 reflects the issuance of our $175 million 10 3/8%
Senior Subordinated Notes in May 1999.
(8)Reflects the issuance of:
- 10.9 million Series C units acquired by a subsidiary of El Paso
Corporation in November 2002;
- 4.1 million common units, which included 1.1 million common units
purchased by an affiliate of our general partner in April 2002;
- 5.6 million common units, which included 1.5 million common units
purchased by an affiliate of our general partner in October 2001;
- 2.3 million common units in March 2001;
- $170 million Series B preference units to a subsidiary of El Paso
Corporation in August 2000; and
- 4.6 million common units in July 2000.
In addition, we redeemed $50 million liquidation value of our Series B
preference units in October 2001.

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

GENERAL

Our objective is to operate as a growth-oriented master limited partnership
(MLP) with a focus on increasing our cash flow, earnings and return to our
unitholders by becoming one of the industry's leading providers of midstream
energy services. Our strategy is to maintain and grow a diversified, balanced
base of strategically located and efficiently operated midstream energy assets
with stable and long-term cash flows. We own or have interests in:

- over 15,700 miles of natural gas gathering and transportation pipelines
with capacity of over 10.3 Bcf/d;

- over 340 miles of offshore oil pipelines with capacity of 635 MBbls/d;

- over 1,000 miles of NGL pipelines with varying capacity of up to 38
MBbls/d;

- five processing/treating plants with capacity of over 1.4 Bcf/d of
natural gas and 50 MBbls/d of NGL;

- four NGL fractionating plants with capacity of 120 MBbls/d of NGL;

- five NGL storage facilities with aggregate capacity of over 24 MMBbls;

- three natural gas storage facilities with aggregate working gas capacity
of over 19 Bcf; and

- six offshore hub platforms, including the Falcon nest platform which we
brought online in March 2003.

In addition, we currently have midstream projects underway in the Gulf of
Mexico with gross estimated capital costs of approximately $904 million,
including 426 miles of oil pipeline, 202 miles of natural gas pipeline and two
platforms, including the Falcon Nest platform which was completed in March 2003.

Our strategy contemplates substantial growth through the development and
acquisition of a wide range of midstream and other energy infrastructure assets,
while maintaining a strong balance sheet. This strategy includes constructing
and acquiring additional assets and businesses to enhance our ability to compete
effectively, diversify our asset portfolio and, thereby, provide more stable
cash flow. Consequently, to fully realize our strategy, we strive to access the
right mix of short, medium, long-term and permanent capital on a cost-effective
basis. We have expanded our credit facilities, obtained project financing and
issued debt and equity securities to meet our financial needs over the past
three years; however, we will need substantial new capital, including future
periodic debt and equity offerings, to continue to finance our strategy.
Significant milestones in the implementation of our strategy over the past three
years include the following:

GENERAL PARTNER RELATIONSHIP

El Paso Energy Partners Company, a Delaware corporation, is our sole
general partner. The business and affairs of our general partner are managed by
a board of directors, comprised of two management directors who are also our
executive officers and three independent directors who meet the independent
director requirements established by the NYSE and the Sarbanes-Oxley Act of
2002. El Paso Energy Partners Company recently announced that the size of the
board will be increased by the addition of two more independent directors.
Through its board of directors, our general partner manages our day-to-day
operations.

Our corporate governance structure and independence initiatives

The market is requesting that public companies institute dramatic
governance changes designed to achieve independence, qualitatively and
quantitatively. Some of the more immediate and fundamental proposed changes
establish and require a higher standard for determining director independence
and require a greater percentage of the members of the board to be independent.
For example, under rules recently proposed by the NYSE:

- at least a majority of the members of the board of a listed company must
be "independent directors;"

- each public company board must form several specific committees -- audit,
governance and compensation -- that must be comprised entirely of
independent directors; and

- the chairperson of the audit committee must be a "financial expert."

The Securities and Exchange Commission and the NYSE have developed
definitions and other guidance to help establish minimum qualifications for
"independent directors" and "financial experts." We are in compliance with all
of these rules, regulations and standards as they apply to our general partner.

We continually strive to improve our corporate governance model. We
recently identified and evaluated a number of changes that could be made to our
corporate structure to better address potential conflicts of interest and to
better balance the risks and rewards of significant relationships with our
affiliates. With respect to the potential changes identified, which are referred
to as Independence Initiatives, we have already implemented the following:

- reconstituted our board of directors with at least a majority of
non-management, independent directors;

- established a governance and compensation committee of our board of
directors consisting solely of independent directors; and

- significantly reduced the percentage of revenue we derive from affiliates
of El Paso Corporation.

We are in the process of implementing the following Independence Initiatives:

- seeking financial assurances from El Paso Corporation and its affiliates
regarding our existing customer/contractual relationships with them;

- adding two more independent directors to our board of directors;

33

- reorganizing our structure, further reducing the interrelationships with
El Paso Corporation, into a Delaware limited liability company that will
be required to have:

- no material assets other than its interests in us;

- no material operations other than those relating to our operations;

- no material debt or other obligations other than those owed to us or
our creditors;

- no material liens other than those securing obligations owed to us or
our creditors; and

- no employees;

- changing our name; and

- negotiating several agreements that could partially mitigate our risks
associated with our ongoing contractual arrangements with El Paso
Corporation or any of its subsidiaries, including a master netting
agreement and a resource support agreement.

Approval must be received from our general partner's board of directors and from
El Paso Corporation prior to consummating the reorganization of the general
partner and executing the master netting agreement and resource support
agreement.

Under the partnership agreement, our general partner has the responsibility
to, among other things, manage and operate our assets. In addition, under our
partnership agreement, our general partner had agreed not to voluntarily
withdraw as general partner on or prior to December 31, 2002. Now that this
obligation of the general partner has expired, our general partner can withdraw
with 90 days notice. We have no employees today, a condition that is common
among MLPs. Although this arrangement has worked well for us in the past and
continues to work well for us, we are evaluating the direct employment of the
personnel who manage the day-to-day operations of our assets.

OUR RELATIONSHIP WITH EL PASO CORPORATION

El Paso Corporation, an NYSE-listed company, is a leading provider of
natural gas services and the largest pipeline company in North America. Through
its subsidiaries, El Paso Corporation:

- owns 100 percent of our general partner, which means that, historically,
El Paso Corporation and its affiliates have employed the personnel who
operate our businesses. We reimburse our general partner and its
affiliates for the costs they incur on our behalf, and we pay our general
partner its proportionate share of distributions -- relating to its one
percent general partnership interest and the related incentive
distributions -- we make to our partners each calendar quarter.

- is a significant stakeholder in us -- it owns approximately 26.5 percent,
or 11,674,245, of our common units, all 10,937,500 of our newly issued
Series C units, which we issued in November 2002 for $350 million, all
125,392 of our outstanding Series B preference units (with a liquidation
value at December 31, 2002 of approximately $158 million), and our one
percent general partner interest. As holders of some of our common units
and all of our Series C units, subsidiaries of El Paso Corporation
receive their proportionate share of distributions we make to our
partners each calendar quarter.

- is a customer of ours. As with other large energy companies, we have
entered into a number of contracts with El Paso Corporation and its
affiliates.

- has in the past publicly announced its intention to use us as its primary
vehicle for growth and development of its midstream energy business;
however, El Paso Corporation is neither contractually nor legally bound
to use us as its primary vehicle for growth and development of midstream
energy assets, and may reconsider its relationship with us at any time,
without notice.

Historically, we have entered into transactions with El Paso Corporation
and its subsidiaries to acquire or sell assets. We have instituted specific
procedures for evaluating and valuing our material transactions with El Paso
Corporation and its subsidiaries. Before we consider entering into a transaction
with El Paso

34

Corporation or any of its subsidiaries, we determine whether the proposed
transaction (i) would comply with the requirements under our indentures and
credit agreements, (ii) would comply with substantive law, and (iii) would be
fair to us and our limited partners. In addition, our general partner's board of
directors utilizes an Audit and Conflicts Committee comprised solely of
independent directors. This committee:

- evaluates and, where appropriate, negotiates the proposed transaction;

- engages an independent financial advisor and independent legal counsel to
assist with its evaluation of the proposed transaction; and

- determines whether to reject or approve and recommend the proposed
transaction.

We will only consummate any proposed material acquisition or disposition with El
Paso Corporation if, following our evaluation of the transaction, the Audit and
Conflicts Committee approves and recommends the proposed transaction and our
general partner's full board of directors approves the transaction.

Our relationship with El Paso Corporation has contributed significantly to
our past growth, and we have important ongoing contractual arrangements with El
Paso Corporation and some of its subsidiaries. However, we are a stand-alone
operating company with significant assets and operations. Our assets, operations
and financial condition are separate and independent from those of El Paso
Corporation. Our credit facilities and other financing arrangements do not
contain cross default provisions or other triggers tied to El Paso Corporation's
financial condition or credit ratings. Nonetheless, due to our relationship with
El Paso Corporation, adverse developments concerning El Paso Corporation could
adversely affect us, even if we have not suffered any similar developments.

The outstanding senior unsecured indebtedness of El Paso Corporation has
been downgraded to below investment grade and is currently rated Caa1 by Moody's
Investors Service (Moody's) and B by Standard & Poor's (S&P). These downgrades
are a result, at least in part, of the outlook for the consolidated business of
El Paso Corporation and its need for liquidity. In the event that El Paso
Corporation's liquidity needs are not satisfied, El Paso Corporation could be
forced to seek protection from its creditors in bankruptcy.

We have publicly disclosed our efforts to further distinguish ourselves
from El Paso Corporation. As a result of this announcement, various parties have
expressed an interest in purchasing all or a portion of our general partner. El
Paso Corporation has the sole responsibility for determining the ultimate
ownership status of the general partner interest. We have publicly acknowledged
that we are meeting with parties interested in acquiring an equity stake in the
general partner but cannot confirm that such interest will result in firm
proposals or, if such firm proposals are received, that El Paso Corporation will
consider such proposals. If El Paso Corporation sells 50 percent or more of its
interest in our general partner without obtaining consent from our lenders, we
will experience a "change in control" under our credit agreements and
indentures, which will effectively cause all amounts outstanding under those
debt instruments to become due.

As discussed previously, we have implemented, and are in the process of
implementing, a number of Independence Initiatives that are designed to help us
better manage the rewards and risks relating to our relationship with El Paso
Corporation. However, even in light of these Independence Initiatives or any
other arrangements, we may still be adversely affected if El Paso Corporation
continues to suffer financial stress.

RELATED PARTY TRANSACTIONS

In our normal course of business we enter into transactions with various
entities controlled directly or indirectly by El Paso Corporation. For the year
ended December 31, 2002, $93 million of our related party revenue came from El
Paso Merchant Energy North America Company (Merchant Energy), a direct
subsidiary of El Paso Corporation. In November 2002, El Paso Corporation
announced its intention to exit the energy trading business. Accordingly, we
expect that we may have to replace our month-to-month, market priced sales of
natural gas to Merchant Energy, which in 2002 represented revenue of
approximately $60 million, with similar arrangements with third parties. In
addition, Merchant Energy could sell or transfer to third parties the natural
gas transportation and storage agreements they have with us, or Merchant Energy
could request a cancellation of the transportation and storage agreements. In
2002, these agreements

35

represented revenue of approximately $33 million. At present, Merchant Energy
continues to fully utilize these agreements. As discussed above, one of our
Independence Initiatives is to reduce our related party transactions in 2003.
Revenues related to our sales of natural gas to Merchant Energy were $1.6
million in January 2003 and $1.2 million in February 2003, decreasing from $8.3
million in December 2002.

For the year ended December 31, 2002, $97 million of our related party
revenue came from El Paso Field Services (Field Services), an indirect
subsidiary of El Paso Corporation and a direct subsidiary of El Paso Tennessee
Pipeline Co. This revenue stream is primarily related to our EPN Texas
fractionation facilities, our Chaco plant and our Indian Basin plant. Field
Services pays us a monthly fixed fee of $0.024 for each gallon of NGL that we
fractionate into component parts at our EPN Texas fractionation facilities.
Field Services receives the NGL we fractionate at our facilities from producers
in south Texas. The fractionated NGL are re-delivered to Field Services at the
tailgate of the plants and then sold by Field Services to various petrochemical
and refining customers located along the Texas Gulf Coast. Prior to our
acquisition of the San Juan assets, Field Services paid us a fee of $0.1344 per
dekatherm of natural gas that we processed at the Chaco plant. With the November
2002 acquisition of the San Juan assets, we purchased, among other assets, the
contracts Field Services had with the San Juan Basin producers and the related
party nature of this processing revenue stream ended. During 2002, Field
Services paid us market based rates for the NGL that we retained as a fee for
processing services at our Indian Basin plant. Beginning in 2003, we are selling
the NGL to third parties. Our revenues from Field Services were $4.6 million in
January 2003 and $2.9 million in February 2003, decreasing from $9.1 million in
December 2002.

In connection with our San Juan assets acquisition, we entered into a
10-year transportation agreement with El Paso Field Services. Beginning January
1, 2003, we will receive a fee of $1.5 million per year for transportation on
our NGL pipeline acquired in the transaction which extends from Corpus Christi
to near Houston. See Item 8, Financial Statements and Supplementary Data, Note 9
for a further discussion of our related party transactions.

LIQUIDITY AND CAPITAL RESOURCES

Our ability to execute our growth strategy and complete our current
projects is dependent upon our access to the capital necessary to fund our
projects and acquisitions. High profile business failures, allegations of
corporate malfeasance, a slow economic recovery and increased unemployment among
other factors have negatively affected the United States capital markets during
2002. Our business and industry have also experienced the adverse affects of the
challenging economic climate during 2002, but we have succeeded in our capital
raising efforts to fund many of our planned projects and acquisitions. Our
continued success with capital raising efforts, including the formation of joint
ventures to share costs and risks, will be the critical factor which determines
how much we actually spend. We believe our access to capital resources is
sufficient to meet the demands of our current and future operating growth needs
and, although we currently intend to make the forecasted expenditures, we may
adjust the timing and amounts of projected expenditures as necessary to adapt to
changes in the capital markets.

CAPITAL RESOURCES

Despite the widely known difficulties in the credit and equity markets, we
successfully raised approximately $948 million in the fourth quarter of 2002 by
(1) entering into our $160 million senior secured term loan; (2) issuing $200
million of 10 5/8% senior subordinated notes; (3) entering into our $237.5
million senior secured acquisition term loan and (4) issuing $350 million of our
Series C units to a subsidiary of El Paso Corporation. We used the proceeds we
received from the $160 million senior secured term loan to reduce amounts
outstanding on our $600 million revolving credit facility. We used the net
proceeds from our $200 million senior subordinated notes, our $237.5 million
senior secured acquisition term loan and our $350 million Series C units we
issued to a subsidiary of El Paso Corporation to purchase the San Juan assets
from subsidiaries of El Paso Corporation. The continued strong operating
performance of our existing assets has enabled us to increase our borrowing
capacity under our financial covenants, effectively increasing our ability to
access cash for executing our operating and growth objectives.

36

In February 2002, our shelf registration statement, as filed with the
Securities and Exchange Commission, covering up to $1 billion of securities
representing limited partnership interests, became effective.

In October 2002, we amended the terms of our $600 million revolving credit
facility and the EPN Holding term credit facility in connection with our
entering into the senior secured term loan. The modifications included, among
other things, (1) entering into the $160 million senior secured term loan
maturing in 2007 as a term component of our revolving credit facility, which we
collectively refer to as our credit facility; (2) designating the EPN Holding
term credit facility as "senior secured" indebtedness in addition to our credit
facility, which is cross-collateralized on an equal basis with all of the
collateral currently pledged under our credit facility and the EPN Holding term
credit facility; (3) aligning, effectively, the covenants in our credit facility
and the EPN Holding term credit facility, including eliminating the restrictions
for distributing cash out of EPN Holding; and (4) terminating the $25 million
revolving credit facility that was formerly part of the EPN Holding term credit
facility.

In November 2002, we further amended our credit facility and the EPN
Holding term credit facility in connection with our borrowing of $237.5 million
under the senior secured acquisition term loan to modify the interest rates the
facilities bear. The modified interest rate we are charged under the terms of
the amendment will remain in effect until the senior secured acquisition term
loan is repaid in full. Under the amended terms of these agreements, the loans
bear interest at our option at either (i) 2.25% plus a variable base rate (equal
to the greater of the prime rate as determined by JP Morgan Chase Bank, the
federal funds rate plus 0.5% or the Certificate of Deposit (CD) rate as
determined by JP Morgan Chase Bank plus 1.00%); or (ii) LIBOR plus 3.50%. The
applicable rates on our revolving credit facility will revert to the historical
rate schedule at LIBOR plus rates ranging from 0.875% to 2.50% or one of the
variable base rates described above plus rates ranging from 0.0% to 1.50%
following repayment of the $237.5 million senior secured acquisition term loan
subject to our meeting certain ratios and attaining certain ratings as set forth
in our credit facility. For the EPN Holding term credit facility, the applicable
rates will revert to the historical rate schedule at LIBOR plus rates ranging
from 1.75% to 2.50% or one of the variable base rates described above plus rates
ranging from 0.50% to 1.25%, following repayment of the $237.5 million senior
secured acquisition term loan, subject to our meeting certain ratios set forth
in the EPN Holding term credit facility. The senior secured acquisition term
loan was repaid in March 2003.

Our credit facility, EPN Holding term credit facility and senior secured
acquisition term loan contain covenants that include restrictions on our and our
subsidiaries' ability to incur additional indebtedness or liens, sell assets,
make loans or investments, acquire or be acquired by other companies and amend
some of our contracts, as well as requiring maintenance of certain financial
ratios. Failure to comply with the provisions of any of these covenants could
result in acceleration of our debt and other financial obligations and that of
our subsidiaries and restrict our ability to make distributions to our
unitholders. The financial covenants associated with these facilities are as
follows:

(a) Consolidated tangible net worth cannot be less than $710.0 million
plus 75 percent of the net proceeds we receive from the future sale or
issuance of any equity securities by us;

(b) The ratio of consolidated EBITDA, as defined in our credit
agreements, to consolidated interest expense cannot be less than 2.0 to
1.0;

(c) The ratio of consolidated total senior indebtedness on the last
day of any fiscal quarter to the consolidated EBITDA for the four quarters
ending on the last day of the current quarter cannot exceed 3.25 to 1.0;
and

(d) The ratio of our consolidated total indebtedness on the last day
of any fiscal quarter through December 31, 2003 to the consolidated EBITDA
for the four quarters ending on the last day of the current quarter cannot
exceed 5.25 to 1.0. The ratio of consolidated total indebtedness to
consolidated EBITDA will decline to 5.0 to 1.0 beginning January 1, 2004.

Among other things, each credit agreement includes as an event of default the
failure of El Paso Corporation and its subsidiaries to own more than 50 percent
of our general partner unless our creditors agree otherwise. At
37

December 31, 2002, we are in compliance with the covenants of our credit
agreements and indentures and we have available for use the entire $109 million
remaining under our revolving credit facility.

We have features contained in our debt instruments described as ratings
triggers. These triggers are contained in our:

- indentures governing our $200 million 10 5/8% Senior Subordinated Notes
due 2012, our $230 million 8 1/2% Senior Subordinated Notes due 2011, our
$250 million 8 1/2% Senior Subordinated Notes due 2011 and our $175
million 10 3/8% Senior Subordinated Notes due 2009, where many covenants
will be suspended in the event we achieve an investment grade credit
rating;

- $237.5 million senior secured acquisition term loan, where the interest
rates we are charged will increase by 1.00% to 1.50% if our credit
ratings decline below the higher of BB+ by S&P or Ba1 by Moody's. This
loan was repaid in March 2003;

- $600 million credit facility, where we will receive a 0.38% to 0.50%
reduction in interest rate if we achieve an investment grade credit
rating; and

- $160 million senior secured term loan, if, at any time, our senior
long-term unsecured debt rating issued by S&P is below BB+ and either our
(a) senior, long-term unsecured debt rating issued by Moody's is below
Ba2, or (b) our senior secured debt rating issued by Moody's is below
Ba1, the interest rate on that term loan increases by 1.00%.

In August 2002, Deepwater Gateway, L.L.C., our joint venture that is
constructing the Marco Polo TLP, obtained a $155 million project finance loan
from a group of commercial lenders to finance a substantial portion of the cost
to construct the Marco Polo TLP and related facilities. Deepwater Gateway may
elect that all or a portion of the project finance loan bear interest at either
i) LIBOR plus 1.75% or ii) an alternate base rate (equal to the greater of the
prime rate, the base CD rate plus 1% or the federal funds rate plus 0.5%, as
those terms are defined in the project finance loan agreement) plus 0.75%.
Deepwater Gateway must also pay commitment fees of 0.375% per year on the unused
portion of the project finance loan. The loan is collateralized by substantially
all of Deepwater Gateway's assets. If Deepwater Gateway defaults on its payment
obligations under the project finance 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 has $27 million outstanding under the project finance loan at an average
interest rate of 3.38% and had not paid us or any of our subsidiaries any
distributions.

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. Upon conversion of the project finance
loan to a term loan, Deepwater Gateway will be required to maintain a debt
service reserve of not less than the projected principal, interest and fees due
on the term loan for the immediately succeeding six month period. In addition,
Deepwater Gateway is prohibited from making distributions until the project
finance loan has been repaid or is converted.

Poseidon Oil Pipeline Company, L.L.C., an unconsolidated affiliate in which
we have a 36 percent joint venture ownership interest, is party to a $185
million credit agreement under which it has outstanding obligations that may
restrict its ability to pay distributions to its owners. The interest rate
Poseidon is charged on balances outstanding under its credit facility is
dependent on its leverage ratio as defined in the Poseidon credit facility.
Poseidon's interest rate at December 31, 2002 was LIBOR plus 1.50% for
Eurodollar loans and a variable base rate equal to the greater of the Prime Rate
or 0.50% plus the Federal Funds rate, (as those terms are defined in the
Poseidon credit facility) plus 0.50% for base rate loans. In January 2002,
Poseidon entered into a two-year interest rate swap agreement to fix the
variable LIBOR based interest rate on $75 million of the $148 million
outstanding under its credit facility at 3.49% through January 2004. Poseidon,
under its credit facility, currently pays LIBOR plus 1.50%, resulting in an
effective interest rate of 4.99% on the hedged notional amount. Poseidon's
interest rate will decrease by 0.25% if their leverage ratio declines below 2.00
to 1.00 or by 0.50% if their leverage ratio declines to 1.00 to 1.00 or less.
Additionally, Poseidon pays commitment fees on the unused portion of the credit
facility at rates that vary from 0.25% to 0.375%.
38

This credit agreement requires Poseidon to maintain a debt service reserve equal
to two quarters' interest and is collateralized by substantially all of
Poseidon's assets. As of December 31, 2002, the remaining $73 million was at an
average interest rate of 3.38%.

Poseidon's credit agreement contains covenants such as restrictions on debt
levels, restrictions on liens collateralizing debt and guarantees, restrictions
on mergers and on the sales of assets and dividend restrictions. A breach of any
of these covenants could result in acceleration of Poseidon's debt and other
financial obligations.

Under the Poseidon revolving credit facility, the financial debt covenants
are:

(a) Poseidon must maintain consolidated tangible net worth in an
amount not less than $75 million plus 100 percent of the net cash proceeds
from the issuance by Poseidon of equity securities of any kind;

(b) the ratio of Poseidon's EBITDA, as defined in Poseidon's credit
agreement, to interest expense paid or accrued during the four quarters
ending on the last day of the current quarter must be at least 2.50 to
1.00; and

(c) the ratio of total indebtedness of Poseidon to EBITDA for the four
quarters ending on the last day of the current quarter shall not exceed
3.00 to 1.00.

Poseidon was in compliance with the above covenants as of December 31,
2002.

SERIES B PREFERENCE UNITS

In August 2000, we issued 170,000 Series B preference units with a value of
$170 million to acquire the Petal and Hattiesburg natural gas storage businesses
from a subsidiary of El Paso Corporation. In October 2001, we redeemed 44,608 of
the Series B preference units for a $50 million liquidation value, including
accrued distributions of approximately $5.4 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.
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. These preference units contain no mandatory
redemption obligation, but may be redeemed at our option at any time.

SERIES C UNITS

In connection with our acquisition of the San Juan assets in November 2002,
we issued to a subsidiary of El Paso Corporation 10,937,500 of our Series C
units, a new class of our limited partner interests, at a price of $32 per unit,
$350 million in the aggregate. The Series C units are similar to our existing
common units, except that the Series C units are non-voting limited partnership
interests. After April 30, 2003, the holder of Series C units will have the
right to cause us to propose a vote of our common unitholders as to whether the
Series C units should be converted into common units. If our common unitholders
approve the conversion, then each Series C unit will convert into a common unit.
If our common unitholders do not approve the conversion within 120 days after
the vote is requested, then the distribution rate for the Series C unit will
increase to 105 percent of the common unit distribution rate in effect from time
to time. Thereafter, the Series C unit distribution rate can increase on April
30, 2004 to 110 percent of the common unit distribution rate and on April 30,
2005 to 115 percent of the common unit distribution rate.

FORECASTED EXPENDITURES

We estimate our forecasted expenditures based upon our strategic operating
and growth plans, which are also dependent upon our ability to produce or
otherwise obtain the capital necessary to accomplish our operating and growth
objectives. These estimates may change due to factors beyond our control, such
as

39

weather-related issues, changes in supplier prices or poor economic conditions.
Further, estimates may change as a result of decisions made at a later date
which may include scope changes or decisions to take on additional partners.

The table below depicts our estimate of expenditures on projects,
acquisitions, operating lease payments and principal repayments of debt
obligations for the year ending December 31, 2003 (in millions). These
expenditures are net of anticipated project financings, contributions in aid of
construction and contributions from joint venture partners including the
anticipated formation of a joint venture with a 50 percent partner for the
development of our Cameron Highway oil pipeline project, and project financing
to fund a portion of the construction costs. Actual results may vary from these
projections. We are contractually committed to the Cameron Highway project
whether or not we obtain a partner or project financing.

DEBT REPAYMENT AND OTHER OBLIGATIONS

See Item 8, Financial Statements and Supplementary Data, Note 6, for a
detailed discussion of our debt obligations.

40

The following table presents the timing and amounts of our debt repayment
and other obligations for the years following December 31, 2002, that we believe
could affect our liquidity (in millions):

We expect to renew our credit facility and raise additional capital during
the next year through the issuance of additional common units and obtaining
project financing for our Cameron Highway joint venture. We repaid our $238
million senior secured acquisition term loan in March 2003 with proceeds from an
issuance of $300 million 8 1/2% Senior Subordinated Notes due 2010. We expect to
use any capital we raise through the issuance of additional common units to
reduce amounts outstanding under our credit facilities, to finance growth
opportunities and for general partnership purposes. Our ability to raise
additional capital may be negatively affected by many factors, including our
relationship with El Paso Corporation.

CASH FROM OPERATING ACTIVITIES

Net cash provided by operating activities was $176.0 million for the year
ended December 31, 2002, compared to $87.4 million for the same period in 2001.
The increase was primarily attributable to operating cash flows generated by our
acquisitions of the Chaco plant in October 2001, the remaining 50 percent
interest in Deepwater Holdings that we did not already own in October 2001, the
EPN Holding assets in April 2002 and the San Juan assets in November 2002. This
increase was partially offset by lower cash distributions in 2002 from Poseidon,
an unconsolidated affiliate.

CASH FROM INVESTING ACTIVITIES

Net cash used in investing activities was approximately $1.2 billion for
the year ended December 31, 2002. Our investing activities include our November
2002 purchase of the San Juan assets, our April 2002 purchase of the EPN Holding
assets, capital expenditures related to the expansion of our Petal natural gas
storage facility and other asset purchases and capital projects. Further
contributing to the expenditures were additions to investments in unconsolidated
affiliates relating to our Marco Polo project. These expenditures were partially
offset by proceeds from the April 2002 sale of our Prince TLP and nine percent
Prince overriding royalty interest to El Paso Production Company and other asset
sales. The Prince assets sales are reflected as net cash provided by investing
activities of discontinued operations in our statement of cash flows.

41

CASH FROM FINANCING ACTIVITIES

Net cash provided by financing activities was approximately $1.1 billion
for the year ended December 31, 2002. During 2002, our cash provided by
financing activities included the issuances of long-term debt and common units,
as well as borrowings under our credit facility, EPN Holding term credit
facility, senior secured term loan and senior secured acquisition term loan.
Cash used in our financing activities included repayments on our EPN Holding
term credit facility, Argo term loan, our credit facility and other financing
obligations, as well as distributions to our partners.

ACQUISITIONS AND CONSTRUCTION PROJECTS

ACQUISITIONS

San Juan Assets

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 interests in the Chaco cryogenic natural gas processing
plant; NGL transportation and fractionation assets located in Texas; and an oil
and natural gas gathering system located in the deeper water regions of the Gulf
of Mexico. As part of this transaction, El Paso Corporation is required 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. With the close of this transaction, the monthly fee under
our general and administrative services agreement with subsidiaries of El Paso
Corporation increased by $1.3 million, bringing our total monthly fee to $2.9
million. 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 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;
42

- 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
----
Initial purchase price...................................... 782
Less working capital and capital expenditure adjustments.... 16
----
Net purchase price.......................................... $766
====

We issued 10,937,500 of our Series C units to El Paso Corporation for a
value of $350 million.

The remaining balance of the purchase price was paid in cash. We funded
this portion of the purchase price with net proceeds of $238 million from a
senior secured acquisition term loan, which was repaid in March 2003 with our
issuance of $300 million 8 1/2% Senior Subordinated Notes, and $194 million from
our issuance of $200 million Senior Subordinated Notes, both of which are
discussed in Item 8, Financial Statements and Supplementary Data, Note 6.

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 approved these transactions.

EPN Holding Assets

In April 2002, EPN Holding acquired from subsidiaries of El Paso
Corporation midstream assets located in Texas and New Mexico, including one of
the largest intrastate pipeline systems in Texas based on miles of pipe. The
acquired 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 the 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.

43

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 TLP and our nine percent Prince
overriding royalty interest............................... 190
----
$735
====

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. The
remaining amount was restructured in October 2002, as discussed in Item 8,
Financial Statements and Supplementary Data, Note 6.

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

Marco Polo Project. In December 2001, we announced an agreement with
Anadarko Petroleum Corporation under which we will construct, install and own
the Marco Polo TLP with capacity to handle 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 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
had not paid us, our joint venture partner or any of our subsidiaries any
distributions.

44

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 costs associated
with the Marco Polo TLP will be funded through the $155 million project finance
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 that 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 income or cash flow. Deepwater Gateway is
managed by a management committee consisting of representative from each of its
members.

In addition, we will construct and own a 36-mile, 14-inch oil pipeline and
a 75-mile, 18 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 the Typhoon natural gas
pipeline. 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. These pipelines are expected to be completed and placed in service in
the first quarter of 2004, and are expected to cost a total of $96 million to
construct. As of December 31, 2002, we have spent approximately $2.6 million on
these pipelines, which are 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.

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.

Phoenix (formerly known as Red Hawk). We announced that 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

45

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.

COMPLETED PROJECTS

Petal Expansion. In June 2002, we completed a $68 million, 8.9 Bcf (6.3
Bcf working capacity) expansion of our Petal natural gas storage facility,
including a withdrawal facility and a 20,000 horsepower compression station
located near Hattiesburg, Mississippi. This brings the total working gas
capacity of the Petal facility to 9.5 Bcf, of which 7 Bcf is dedicated to a
subsidiary of The Southern Company, one of the largest producers of electricity
in the United States, under a 20-year fixed-fee contract. In June 2002, we also
completed a $100 million, 60-mile pipeline addition, including a 9,000
horsepower compression station, with capacity of 1.25 Bcf/d (currently
FERC-certified to 700 MMcf/d) that interconnects with the storage facility and
offers direct interconnects with the Southern Natural Gas, Transco and Destin
pipeline systems. In June 2002, the interconnects with Southern Natural Gas and
Destin were placed into service. In September 2002, the Transco interconnect was
placed in service.

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, with capacity to handle 400 MMcf/d of natural gas. 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.

OTHER MATTERS

As a result of current circumstances generally surrounding the energy
sector, the creditworthiness of several industry participants has been called
into question, including El Paso Corporation, the indirect parent of our general
partner. As a result of these general circumstances, we have established an
internal group to monitor our exposure to, and determine, as appropriate,
whether we should request prepayments, letters of credit or other collateral
from our counterparties. If these general conditions worsen and, as a result,
several industry participants file for Chapter 11 bankruptcy protection, it
could have a material adverse effect on our financial position, results of
operations or cash flows.

46

RESULTS OF OPERATIONS

Our business activities are segregated into four distinct operating
segments:

- Natural gas pipelines and plants;

- Oil & NGL logistics;

- Natural gas storage; and

- Platform services.

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. In
October 2001, we acquired the Chaco plant and reflected the operations of this
asset in our Oil and NGL logistics segment. With the change in our segments, we
moved the Chaco processing plant to our Natural gas pipelines and plants
segment. As a result of our sale of the Prince TLP and our nine percent
overriding interest in the Prince Field in April 2002, the results of operations
from these assets are reflected as discontinued operations in our statements of
income for all periods presented and are not reflected in our segment results
below. Beginning in 2002, operations from our oil and natural gas production
activities are reflected in "Other."

To the extent possible, results of operations have been reclassified to
conform to the current business segment presentation, although these results may
not be indicative of the results which would have been achieved had the revised
business segment structure been in effect during those periods. Operating
revenues and expenses by segment include intersegment revenues and expenses
which are eliminated in consolidation. For a further discussion of the
individual segments, see Item 8, Financial Statements and Supplementary Data,
Note 14.

We use earnings before interest and income taxes (EBIT) to assess the
operating results and effectiveness of our business segments. We define EBIT as
operating income, adjusted for several items, including: earnings from
unconsolidated affiliates, minority interest of consolidated subsidiaries, gains
and losses on sales of assets and other miscellaneous non-operating items. Items
that are not included in this measure are financing costs, including interest
and debt expense, income tax benefit and discontinued

47

operations. The following is a reconciliation of our operating results to EBIT
and income from continuing operations for the years ended December 31:

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

(1) Represents predominately our oil and natural gas production activities as
well as intersegment eliminations. Our intersegment revenues, along with our
intersegment operating expenses, consist of normal course of business-type
transactions between our operating segments.

We believe this measurement is useful to our investors because it allows
them to evaluate the effectiveness of our business and operations and our
investments from an operational perspective, exclusive of the costs to finance
those activities and exclusive of income taxes, neither of which are directly
relevant to the efficiency of those operations. This measurement may not be
comparable to measurements used by other companies and should not be used as a
substitute for net income or other performance measures.

48

SEGMENT RESULTS

NATURAL GAS PIPELINES AND PLANTS

The Natural gas pipelines and plants segment includes the EPGT Texas
intrastate pipeline system, the Viosca Knoll system, the HIOS system, the East
Breaks system, the EPIA system, the Chaco cryogenic natural gas processing
plant, the Indian Basin processing and treating facility, the San Juan natural
gas gathering system and related assets, and the Typhoon natural gas pipeline.
The natural gas gathering and transportation pipelines, which receive natural
gas from producing properties in Alabama, Colorado, Louisiana, Mississippi, New
Mexico, Texas and the Gulf of Mexico, primarily earn revenue from
fixed-fee-based services or market-based rates that are usually related to the
monthly natural gas price index for volume gathered. Offshore pipelines often
involve life-of-reserve commitments with both firm and interruptible components,
whereas onshore pipelines generally have contracts for a specific number of
years or are month to month. The Chaco plant receives and processes natural gas
from the San Juan Basin. The Indian Basin facility receives and processes
natural gas from the Permian Basin. EPIA provides transportation services as
well as marketing services through the purchase of natural gas from regional
producers and others, and the sale of natural gas to local distribution
companies and others. Beginning in 2001, we entered into fixed-for-floating
commodity price swaps to hedge our commodity price exposure to EPIA's fixed
price sales of natural gas, resulting in a fixed margin on the sales. These
fixed price sales agreements represent less than two percent of EPIA's revenue
or an average of 70 MDth/d. There was no significant impact on our realized cost
of natural gas from these swaps for the year ended December 31, 2002. However,
as a result of these swaps, our realized cost of natural gas may differ from the
actual market prices of natural gas in future periods.

Starting in April 2002, in connection with our EPN Holding acquisition, we
had swaps in place for our interest in the Indian Basin processing plant to
hedge the price received for the sale of natural gas liquids. All of these
hedges expired by December 31, 2002. We did not have any ineffectiveness in our
hedging relationship since all sale prices are based on the same index and
volumes as the hedged transactions. In connection with our acquisition of the
San Juan assets in November 2002, we entered into a derivative financial
instrument to hedge our exposure during 2003 relating to gathering activities
for changes in natural gas prices in the San Juan Basin. No ineffectiveness
exists in our hedging relationship because all purchase and sale prices are
based on the same index and volumes as the hedge transactions.

49

The following table presents EBIT derived from our Natural gas pipelines
and plants segment and the related volumes associated with the indicated
pipeline or plant (in thousands, except for volumes):

- ----------
(1) We purchased the Texas Intrastate assets, and the Carlsbad and Waha systems,
which are included in the Permian gathering systems, in April 2002, as part
of the EPN Holding acquisition.

(2) We purchased the San Juan gathering system, the remaining interest in the
Chaco processing plant and the Typhoon natural gas pipeline in November
2002, as part of the San Juan assets acquisition.

In connection with our April 2002 EPN Holding acquisition, we added assets
to this segment with contracts under which we purchase natural gas from
producers at the wellhead for an index price less an amount that compensates us
for gathering services. We then sell the natural gas into the open market at
points on our system at the same index prices. Accordingly, our operating
revenues and costs of natural gas are impacted by changes in energy commodity
prices, while our margin is unaffected. For these reasons, we believe that gross
margin (revenue less cost of natural gas) provides a more accurate and
meaningful basis for analyzing operating results for the Natural gas pipelines
and plants segment.

YEAR ENDED 2002 COMPARED TO YEAR ENDED 2001

Natural gas pipelines and plants margin for the year ended December 31,
2002, was $199.5 million higher than in 2001, primarily attributed to these
asset acquisitions:

The margin on the assets we owned for the full years in 2001 and 2002
decreased by $0.6 million in 2002 as a result of Hurricane Isidore in September
2002 and Hurricane Lili in October 2002, partially offset by additional volumes
from production in the Camden Hills and Aconcagua Fields areas of the Gulf of
Mexico, which are delivered to our Viosca Knoll system.

Other operating expenses for the year ended December 31, 2002 were $100.2
million higher than the same period in 2001 primarily due to our April 2002
purchase of the EPN Holding assets, our purchase of the
50

Chaco plant in October 2001, our consolidation of Deepwater Holdings and the
purchase of the San Juan assets in November 2002. Excluding the operating costs
of the newly acquired assets, other operating expenses increased by $2.3 million
primarily due to an increase in EPIA's operating fee and an increase in gas
imbalance cost on Viosca Knoll.

Other income for the year ended December 31, 2002, was $5.3 million lower
than the same period in 2001 primarily due to our recognition in 2001 of $22.0
million in additional consideration from El Paso Corporation associated with the
sale of our Gulf of Mexico pipeline assets in 2001, partially offset by net
losses of $7.8 million due to the sale of our interests in the Tarpon and Green
Canyon pipeline assets in January 2001. Also contributing to this decrease were
lower earnings from unconsolidated affiliates of $9.8 million, which primarily
relates to Deepwater Holdings' sale of Stingray, UTOS and the West Cameron
dehydration facility and the sale of our interest in Nautilus and Manta Ray
Offshore in 2001. Other loss for 2002 reflects additional losses associated with
the sale of our Gulf of Mexico assets, offset by a gain on the sale of other
assets and earnings from Coyote Gas Treating, LLC, an unconsolidated affiliate
in which we acquired an interest in as part of the San Juan assets acquisition
in November 2002.

YEAR ENDED 2001 COMPARED TO YEAR ENDED 2000

Natural gas pipelines and plants margin for the year ended December 31,
2001, was $13.5 million higher than in 2000. Approximately $17.4 million is due
to our consolidation of Deepwater Holdings, our purchase of the Chaco plant in
October 2001, our Indian Basin lateral, which went into service in June 2001,
and an increase of $1.8 million due to higher volumes on EPIA as a result of a
full twelve months of ownership in 2001 as well as larger spreads between
natural gas sales prices and the cost to purchase natural gas in 2001. We
acquired EPIA in March 2000. These increases were partially offset by a $3.2
million decrease due to lower volumes on the Viosca Knoll gathering system due
to Tropical Storm Barry in August 2001 and a $3.0 million decrease due to the
sale of the Tarpon and Green Canyon pipeline assets in January 2001.

Other operating expenses for the year ended December 31, 2001, were $17.4
million higher than in 2000, primarily due to our consolidation of Deepwater
Holdings, our purchase of the Chaco plant in October 2001, and the abandonment
and impairment of the Manta Ray pipeline in January 2001, which was partially
offset by lower operating expenses resulting from our sales of assets in January
2001. We abandoned the Manta Ray pipeline as a result of our January 2001 sale
of the Manta Ray Offshore system.

Other income for the year ended December 31, 2001, was $5.7 million lower
than in 2000, primarily due to lower earnings from unconsolidated affiliates of
$20.0 million, which primarily relates to Deepwater Holdings' sale of Stingray,
UTOS, and the West Cameron dehydration facility and the sale of our interest in
Nautilus and Manta Ray Offshore during the first six months of 2001 and the
related losses on these sales. Also, we had a decrease in earnings from
unconsolidated affiliates due to our consolidation of Deepwater Holdings in
October 2001. Further contributing to the decrease in other income were net
losses on sales of assets of $7.8 million due to the sales of our interests in
the Tarpon and Green Canyon pipeline assets in January 2001 and a gain on the
sale of other assets in 2000. These decreases were offset by $22 million of
additional consideration from El Paso Corporation related to the sales of our
Gulf of Mexico pipeline assets.

OIL AND NGL LOGISTICS

The Oil and NGL logistics segment includes the NGL transportation pipelines
and fractionation plants of EPN Texas, the Poseidon, Allegheny and Typhoon
offshore oil pipelines, the Almeda fractionator and other Texas NGL assets. The
EPN Texas plants fractionate NGL into ethane, propane, butane and natural
gasoline products which are used by refineries and petrochemical plants along
the Texas Gulf Coast. We receive a fixed fee for each barrel of NGL transported
and fractionated by the EPN Texas facilities from a subsidiary of El Paso
Corporation. We have dedicated 100 percent of EPN Texas' fractionation
facilities' capacity to this subsidiary of El Paso Corporation. The crude oil
pipeline systems serve production activities in the Gulf of Mexico. Revenues
from our oil pipelines are generated by production from reserves committed under
long-term contracts for the productive life of the relevant field.

51

In connection with our San Juan assets acquisition in November 2002, we
added the Typhoon Oil Pipeline to this segment. Typhoon Oil Pipeline's
transportation agreement with two customers provides that Typhoon Oil purchase
the oil produced at the inlet of its pipeline for an index price less an amount
that compensates Typhoon Oil for transportation services. At the outlet of its
pipeline, Typhoon Oil resells this oil back to these producers at the same index
price. Typhoon Oil reflects these sales in gathering and processing revenues and
the related purchases as cost of oil. For these reasons, we believe that gross
margin (revenue less cost of oil) provides a more accurate and meaningful basis
for analyzing operating results for the Oil and NGL logistics segment.

The following table presents EBIT derived from our Oil and NGL logistics
segment and the volumes associated with the indicated asset.

- ----------
(1) We purchased the Typhoon oil pipeline in November 2002, as part of the San
Juan assets acquisition.

(2) Represents 100 percent of Poseidon volumes.

YEAR ENDED 2002 COMPARED TO YEAR ENDED 2001

Margin for the year ended December 31, 2002, was $5.3 million higher than
the same period in 2001, primarily due to our acquisitions of the EPN Texas
transportation and fractionation assets in February 2001, the Hattiesburg
propane storage facility in January 2002, and the Anse La Butte NGL storage
facility in December 2001. Additionally, in November 2002, we purchased Texas
NGL facilities and an oil gathering system located in the deep water regions of
the Gulf of Mexico, referred to as Typhoon Oil. Excluding assets purchased, our
margin was $1.2 million higher primarily as a result of higher volumes on
Allegheny.

Other operating expenses for the year ended December 31, 2002, were $4.5
million higher than the same period in 2001 primarily due to our acquisitions of
the EPN Texas transportation and fractionation assets in February 2001, the
Hattiesburg propane storage facility in January 2002, the Anse La Butte NGL
storage facility in December 2001, the Typhoon Oil Pipeline and Texas NGL
facilities in November 2002. Excluding assets purchased, our other operating
expenses were $1.0 million lower as a result of modifying the operating
agreement in connection with the EPN Holding acquisition in April 2002 between
EPN Texas and El Paso Field Services.

Other income for the year ended December 31, 2002, was $4.8 million lower
than the same period in 2001 primarily due to a decrease in earnings from
unconsolidated affiliates due to lower volumes on Poseidon Oil Pipeline
partially attributable to Hurricane Isidore in September 2002 and Hurricane Lili
in October 2002. Offsetting this impact, were additional volumes related to new
contracts entered into by Poseidon Oil Pipeline. These contracts started in
November 2002 and December 2002 and have a six month duration. We will realize
our 36 percent share of the volume increase through earnings from unconsolidated
affiliates over the next four months.
52

YEAR ENDED 2001 COMPARED TO YEAR ENDED 2000

Revenues for the year ended December 31, 2001, were $24.0 million higher
and other operating expenses were $10.7 million higher than in 2000, primarily
due to the purchase of EPN Texas in February 2001. Excluding this acquisition,
revenues were down $1.2 million due to decreased volumes on Allegheny as a
result of platform shut-ins attributable to maintenance and tropical storm
activity in late 2001.

Other income for the year ended December 31, 2001, was $3.8 million higher
than in 2000, primarily due to an increase in earnings from unconsolidated
affiliates of $5.5 million related to lower average interest rates on Poseidon's
revolving credit facility in 2001 and lower earnings in 2000 resulting from
Poseidon's pipeline rupture in January 2000. Partially offsetting this increase
was the receipt of $1.7 million for business interruption insurance proceeds in
2000 related to the Poseidon pipeline rupture.

NATURAL GAS STORAGE

The Natural gas storage segment includes the Petal and Hattiesburg storage
facilities, which were acquired in August 2000, and a leased interest in the
Wilson natural gas storage facility, located in Wharton County, Texas, which we
acquired in April 2002. The Petal and Hattiesburg storage facilities 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.
As a result of the successful completion of this 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.

For the years ended December 31, 2002, 2001 and 2000, the revenues from
these facilities consist primarily of fixed reservation fees for natural gas
storage capacity. Natural gas storage capacity revenues are recognized and due
during the month in which capacity is reserved by the customer, regardless of
the capacity

53

actually used. We also receive fees for injections and withdrawals by our
customers and interruptible storage fees. The following table presents EBIT
derived from our Natural gas storage segment:

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

(1) Combined injections and withdrawals volumes.

YEAR ENDED 2002 COMPARED TO YEAR ENDED 2001

Natural gas storage revenue for the year ended December 31, 2002, was $9.2
million higher than the same period in 2001 primarily due to the expansion of
the Petal storage facility and our acquisition of the Wilson storage facility
lease in April 2002. Excluding the increase in margin from the Petal expansion
and our acquisition of the Wilson storage facility lease, margin was down $2.3
million primarily as a result of a decrease in revenues attributable to
interruptible storage services.

Operating expenses for the year ended December 31, 2002, were $8.7 million
higher than the same period in 2001 primarily due to the expansion of our Petal
storage facility in the second quarter of 2002, the acquisition of the Wilson
storage facility lease in April 2002 and a favorable resolution of an imbalance
settlement in 2001.

YEAR ENDED 2001 COMPARED TO YEAR ENDED 2000

The overall change in revenue and operating expenses is primarily the
result of owning the Petal and Hattiesburg storage facilities for the full year
of 2001. Fourth quarter 2001 revenues were $4.3 million compared to $4.6 million
in 2000. This decrease was due to lower interruptible storage volumes in the
fourth quarter of 2001. The overall change in operating expenses is primarily
the result of owning the Petal and Hattiesburg storage facilities for the full
year of 2001. Operating expenses for the fourth quarter of 2001 were not
significantly changed from the fourth quarter of 2000.

We did not have any natural gas storage operations prior to August 2000.

PLATFORM SERVICES

The Platform services segment consists of the East Cameron 373, Viosca
Knoll 817, Garden Banks 72, Ship Shoal 331, and Ship Shoal 332 platforms. These
offshore platforms are used to interconnect our offshore pipeline grid, assist
in performing pipeline maintenance, and conduct drilling operations during the
initial development phase of an oil or natural gas property. Platform revenues
are based on fixed and commodity charges. Fixed fees are recognized during the
month reserved by the customer, regardless of how much

54

capacity is actually used. Commodity fees are variable in nature and recognized
when the service is provided. As part of our acquisition of the EPN Holding
assets from subsidiaries of El Paso Corporation in April 2002, we sold the
Prince TLP to a subsidiary of El Paso Corporation. The following table presents
EBIT derived from our Platform services segment and volumes associated with each
platform.

YEAR ENDED 2002 COMPARED TO YEAR ENDED 2001

Platform services revenue for the year ended December 31, 2002, was $2.1
million lower than in the same period in 2001 primarily due to the expiration in
June 2002, in accordance with the original contract terms, of the fixed fee
portion of the Viosca Knoll 817 platform access fee contract with Flextrend
Development Company, our wholly owned subsidiary with production activities. The
decrease was partially offset by one-time billing adjustments for fixed monthly
platform access fees and a gas dehydration fee contract on the East Cameron 373
platform.

Other income for the year ended December 31, 2002, reflects income from an
intersegment investment that is eliminated in our Other segment in
consolidation. Other loss for the year ended December 31, 2001, included
approximately $4.0 million of losses recognized on the sales of the Gulf of
Mexico platform assets, partially offset by $3.4 million of additional
consideration from El Paso Corporation related to the sale of these assets.

YEAR ENDED 2001 COMPARED TO YEAR ENDED 2000

Platform services revenue for the year ended December 31, 2001, was $1.2
million higher than in 2000, primarily due to increased volumes on East Cameron
373. The increase was partially offset by lower volumes on Garden Banks 72 due
to a temporary shut-in of wells.

Operating expenses for the year ended December 31, 2001, were $2.9 million
higher than in 2000, primarily due to the favorable resolution of litigation in
June 2000.

Other loss for the year ended December 31, 2001, included approximately
$4.0 million of losses recognized on the sales of the Gulf of Mexico platform
assets, partially offset by $3.4 million of additional consideration from El
Paso Corporation related to the sale of these assets.

OTHER

Our oil and natural gas production interests in the Garden Banks 72, Garden
Banks 117 and Viosca Knoll 817 Blocks principally comprise the non-segment
activity. Production from these properties is gathered, transported, and
processed through our pipeline systems and platform facilities. Oil and natural
gas production

55

volumes are produced and sold to various third parties and subsidiaries of El
Paso Corporation at the market price. Revenue is recognized in the period of
production. These revenues may be impacted by market changes, hedging
activities, and natural declines in production reserves. We are reducing our oil
and natural gas production activities by not acquiring additional properties due
to their 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.

YEAR ENDED 2002 COMPARED TO YEAR ENDED 2001

EBIT related to non-segment activity for the year ended December 31, 2002,
was $8.8 million lower than in the same period in 2001. The decrease was
primarily due to lower natural gas and oil prices through most of 2002, as well
as lower volumes attributable to a decrease in production as a result of normal
decline of existing reserves. Further contributing to the decrease in income
before interest and income taxes is decreased interest income on the additional
consideration from El Paso Corporation related to the sale of the Gulf of Mexico
assets as well as lower revenue due to Hurricane Isidore in September 2002 and
Hurricane Lili in October 2002.

YEAR ENDED 2001 COMPARED TO YEAR ENDED 2000

EBIT related to non-segment activity for the year ended December 31, 2001
was $17.7 million higher than the same period in 2000. The increase was a result
of higher realized natural gas prices, higher oil production volumes and lower
depletion from natural gas production as a result of upward revisions of prior
estimates of reserve quantities.

INTEREST AND DEBT EXPENSE

YEAR ENDED 2002 COMPARED TO YEAR ENDED 2001

Interest and debt expense on continuing operations, net of capitalized
interest, for the year ended December 31, 2002, was approximately $42.0 million
higher than the same period in 2001. This increase is primarily due to an
increase in the average outstanding balance of our revolving credit facility,
the amounts outstanding under the EPN Holding term credit facility which we
entered to purchase the EPN Holding assets in April 2002, and the $230 million
8 1/2% senior subordinated notes issued in May 2002. Additionally, interest
expense increased by approximately $5.2 million as a result of additional
indebtedness we incurred in the fourth quarter of 2002 (see Item 8, Financial
Statements and Supplementary Data, Note 6) in connection with our San Juan
assets acquisition including additional interest expense associated with
amending our credit facility and the EPN Holding term credit facility.
Capitalized interest for the year ended December 31, 2002 was $5.6 million
compared to $11.8 million for the same period in 2001.

We expect our interest and debt expense to increase in 2003 by
approximately $43.2 million due to the additional debt we incurred during the
fourth quarter of 2002, and the change in interest rates resulting from amending
our credit facility and the EPN Holding term credit facility. We computed the
expected increase employing the weighted average interest rates in effect and
balances outstanding at December 31, 2002.

YEAR ENDED 2001 COMPARED TO YEAR ENDED 2000

Interest and debt expense, net of capitalized interest, for the year ended
December 31, 2001, was approximately $5.3 million lower than 2000. This decrease
primarily relates to an increase in capitalized interest of approximately $4.1
million due to an increase in our construction activity in 2001, as well as
lower average interest rates in 2001. The overall decrease in interest expense
was partially offset by the issuance of $250 million of 8 1/2% Senior
Subordinated Notes in May 2001.

COMMITMENTS AND CONTINGENCIES

See Item 8, Financial Statements and Supplementary Data, Note 10, for a
discussion of our commitments and contingencies.

56

CRITICAL ACCOUNTING POLICIES

The selection and application of accounting policies is an important
process that has developed as our business activities have evolved and as the
accounting rules have developed. Accounting rules generally do not involve a
selection among alternatives, but involve an implementation and interpretation
of existing rules, and the use of judgment, to the specific set of circumstances
existing in our business. We make every effort to properly comply with all
applicable rules on or before their adoption, and we believe the proper
implementation and consistent application of the accounting rules is critical.
However, not all situations are specifically addressed in the accounting
literature. In these cases, we must use our best judgment to adopt a policy for
accounting for these situations. We accomplish this by analyzing similar
situations and the accounting guidance governing them, and often consult with
our independent accountants about the appropriate interpretation and application
of these policies. In addition, the preparation of our financial statements in
conformity with accounting policies generally accepted in the United States
requires us to make estimates and assumptions that affect the reported amounts
of assets, liabilities, revenues and expenses and disclosure of contingent
assets and liabilities that exist at the date of our financial statements. While
we believe our estimates are appropriate, actual results can, and often do,
differ from those estimates. Our critical accounting policies are discussed
below. Each of these areas involves complex situations and a high degree of
judgment either in the application and interpretation of existing literature or
in the development of estimates that impact our financial statements.

Reserves for Contingencies

We accrue reserves for contingent liabilities including, but not limited
to, environmental remediation and clean-up costs, and potential legal claims,
when our assessments indicate that it is probable that a liability has been
incurred and an amount can be reasonably estimated. Our estimates for these
liabilities are based on currently available facts and our estimates of the
ultimate outcome or resolution of the liability in the future. Our actual
results may differ from our estimates, and our estimates can be, and often are,
revised in the future, either negatively or positively, depending upon the
outcome or expectations based on the facts surrounding each exposure.

We currently have a reserve for environmental matters; however, we have no
reserves for non-environmental legal matters. New environmental developments,
such as increasingly strict environmental laws and regulations and new claims
for damages to property, employees, other persons and the environment resulting
from current or past operations, could result in substantial cost and future
liabilities. Also, new legal matters, adverse rulings or anticipated adverse
rulings on pending legal matters, or proposed settlements on pending legal
matters could result in substantial cost or future liabilities.

Asset Impairment

The asset impairment accounting rules require us to determine if an event
has occurred indicating that a long-lived asset may be impaired. In certain
cases, a clearly identifiable triggering event does not occur, but rather a
series of individually insignificant events over a period of time leads to an
indication that an asset may be impaired. We continually monitor our businesses
and the market and business environments and make our judgments and assessments
concerning whether a triggering event has occurred. If an event occurs, we must
make an estimate of our future cash flows from these assets to determine if the
asset is impaired. These cash flow estimates require us to make projections and
assumptions for many years into the future for pricing, demand, competition,
operating costs, legal, regulatory and other factors. Changes in the economic
and business environment in the future, such as production declines that are not
replaced by new discoveries, long term decreases in the demand or price of oil
and natural gas, may lead to an indication that an impairment may have occurred.

Depreciation of Property, Plant and Equipment

We estimate our depreciation based on an estimated useful life and residual
salvage values. Estimated dismantlement, restoration and abandonment costs are
taken into account in determining depreciation

57

provisions for gathering pipelines, platforms, related facilities and oil and
natural gas properties. At the time we place our assets into service, we believe
our estimates are accurate. However, circumstances in the future may develop
which would cause us to change these estimates and in turn would change our
depreciation amounts on a going forward basis. Some of these circumstances
include changes in laws and regulations relating to restoration and abandonment
requirements; changes in the expected costs for dismantlement, restoration and
abandonment as a result of changes, or expected changes, in labor, materials and
other related costs associated with these activities; changes in the useful life
of an asset based on the actual known life of similar assets, changes in
technology, or other factors; and changes in expected salvage proceeds as a
result of a change, or expected change, in the salvage market.

Oil and Natural Gas Reserves and Amortization of Oil and Natural Gas
Properties

The process of estimating quantities of natural gas and crude oil reserves
is very complex, requiring significant decisions in the evaluation of all
available geological, geophysical, engineering and economic data. The data for a
given field may also change substantially over time as a result of numerous
factors including, but not limited to, additional development activity, evolving
production history and continual reassessment of the viability of production
under varying economic conditions. As a result, material revisions to existing
reserve estimates may occur from time to time. Although every reasonable effort
is made to ensure that reserve estimates reported represent the most accurate
assessments possible, the subjective decisions and variances in available data
for various fields make these estimates generally less precise than other
estimates included in the financial statement disclosures. We use the
units-of-production method to amortize capitalized costs of our oil and natural
gas properties. Changes in reserve quantities as described above will cause
corresponding changes in depletion expense in periods subsequent to the quantity
revision.

Volume Measurement

We record amounts for natural gas gathering and transportation revenue,
liquid transportation and handling revenue, natural gas and oil sales and
related natural gas and oil purchases, and the sale of production based on
volumetric calculations. Variances resulting from such calculations are inherent
in our business.

Revenue and Cost of Natural Gas, Oil and Other Products Estimates

Each month we record an estimate for our operating revenues and cost of
natural gas, oil and other products along with a true-up of the prior month's
estimate to equal prior month's actual data. Accordingly, there is one month of
estimate data recorded in our operating revenues and cost of natural gas, oil
and other products accounts for the years ended December 31, 2002, 2001 and
2000. The estimates are based on actual volume and price data through the first
part of the month then extrapolated to the end of the month, adjusted
accordingly for any known or expected changes in volumes or rates through the
end of the month.

Price Risk Management Activities

We account for price risk management activities based upon the fair value
accounting methods prescribed by SFAS No. 133 which prescribes our accounting
for hedging activities and other derivatives. This accounting rule requires that
we determine the fair value of the financial instruments we use in these
business activities and reflect them in our balance sheet at their fair values.
The changes in the fair value from period to period of cash flow hedges are
reported in Other Comprehensive Income (OCI). The gains and losses from the
changes in fair value of derivative instruments that are reported in OCI are
reclassified to earnings in the periods in which earnings are impacted by the
hedged items.

One of the primary factors that can have an impact on our results each
period is the price assumptions used to value our cash flow hedges. We use
published market price information where available, or quotations from traders
in the market to find executable bids and offers. If the fair value of our
hedges cannot be determined from readily available market-based information, we
use internal valuation techniques or models to estimate the fair value of such
instruments. Such modeling techniques generally are only required to extrapolate
the prices of the NGL (for which market-based prices are not readily available
beyond three to

58

six months) based on historical pricing relationships between natural gas, crude
oil and the NGL components. Our estimates also reflect the potential impact of
liquidating our position in an orderly manner over a reasonable period of time
under present market conditions, modeling risk, credit risk of our
counterparties and operational risk. The amounts we report in our financial
statements change as these estimates are revised to reflect actual results,
changes in market conditions or other factors, many of which are beyond our
control.

At inception and on an ongoing basis, we conduct correlation analysis
between the price of the exposure we are hedging, and the hedging instrument. We
use hedge accounting where we conclude that the derivative that we will enter
into will be highly effective in offsetting the price volatility of the item
being hedged. If a financial instrument we have entered into is no longer
effective in offsetting price volatility, it can no longer be designated as a
cash flow hedge and changes in the fair value would be reported directly in the
income statement.

Gas Imbalances

We record imbalance receivables and payables when a customer delivers more
or less gas into our pipelines than they take out. We primarily estimate the
value of our imbalances at prices representing the estimated value of the
imbalances upon settlement. Changes in natural gas prices may impact our
valuation. We do not value our imbalances based on current month prices because
it is not likely that we would purchase or receive natural gas at that point in
time to settle the imbalance.

NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

We continually monitor and revise our accounting policies as developments
occur. At this time, there are several new accounting pronouncements that have
recently been issued, but are not yet adopted, which will impact our accounting
when these rules become effective in the future. Some of these new rules may
have an impact on our critical accounting policies.

For further details on our accounting policies, and the estimates,
assumptions and judgments we use in applying these policies and a discussion of
new accounting rules, see Item 8, Financial Statements and Supplementary Data,
Note 1.

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RISK FACTORS AND CAUTIONARY STATEMENT

This report contains or incorporates by reference forward-looking
statements. Where any forward-looking statement includes a statement of the
assumptions or bases underlying the forward-looking statement, we caution that,
while we believe these assumptions or bases to be reasonable and made in good
faith, assumed facts or bases almost always vary from the actual results, and
the differences between assumed facts or bases and actual results can be
material, depending upon the circumstances. Where, in any forward-looking
statement, we or our management express an expectation or belief as to future
results, such expectation or belief is expressed in good faith and is believed
to have a reasonable basis. We cannot assure you, however, that the statement of
expectation or belief will result or be achieved or accomplished. The words
"believe", "expect", "estimate", "anticipate" and similar expressions may
identify forward-looking statements. All of our forward-looking statements,
whether written or oral, are expressly qualified by these ordinary cautionary
statements and any other cautionary statements that may accompany such
forward-looking statements. In addition, we disclaim any obligation to update
any forward-looking statements to reflect events or circumstances after the date
of this report.

With this in mind, you should consider the following important factors that
could cause actual results to differ materially from those expressed in any
forward-looking statement made by us or on our behalf.

RISKS RELATED TO OUR BUSINESS

OUR INDEBTEDNESS COULD ADVERSELY RESTRICT OUR ABILITY TO OPERATE, AFFECT OUR
FINANCIAL CONDITION AND PREVENT US FROM FULFILLING OUR OBLIGATIONS UNDER OUR
DEBT SECURITIES.

We have a significant amount of indebtedness and the ability to incur
substantially more indebtedness. As of December 31, 2002, we had approximately
$1.0 billion outstanding under four senior secured credit facilities and $858
million outstanding under indentures related to our senior subordinated notes.
After our March 2003 issuance of senior subordinated notes, we had approximately
$1.2 billion outstanding under indentures related to our senior subordinated
notes.

From time to time, our joint ventures also incur indebtedness. As of
December 31, 2002, Poseidon Oil Pipeline Company, L.L.C., in which we own a 36
percent interest, had $148 million outstanding under its revolving credit
facility and Deepwater Gateway, L.L.C., in which we own a 50 percent interest,
had $27 million outstanding under its project finance loan. If Deepwater Gateway
defaults on its payment obligations, 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. Our obligation to make such a payment is
collateralized by substantially all of our assets on the same basis as our
obligations under our credit facility, our senior secured acquisition term loan
and the EPN Holding term credit facility.

We and all of our subsidiaries, except for our unrestricted subsidiaries,
must comply with various affirmative and negative covenants contained in the
indentures related to our senior subordinated notes, and our credit facilities.
Among other things, these covenants limit the ability of us and our
subsidiaries, except for our unrestricted subsidiaries, to:

- incur additional indebtedness or liens;

- make payments in respect of or redeem or acquire any debt or equity
issued by us;

- sell assets;

- make loans or investments;

- acquire or be acquired by other companies; and

- amend some of our contracts.

We do not have the right to prepay the balance outstanding under our senior
subordinated notes without incurring substantial economic penalties.
Additionally, we are required to use the net proceeds of any securities
offerings we complete to repay our senior secured acquisition term loan. The
restrictions under our

60

indebtedness may prevent us from engaging in certain transactions which might
otherwise be considered beneficial to us and could have other important
consequences to you. For example, they could:

- increase our vulnerability to general adverse economic and industry
conditions;

- limit our ability to make distributions to unitholders, including our
minimum quarterly distribution amounts, to fund future working capital,
capital expenditures and other general partnership requirements; to
engage in future acquisitions, construction or development activities; or
to otherwise fully realize the value of our assets and opportunities
because of the need to dedicate a substantial portion of our cash flow
from operations to payments on our indebtedness or to comply with any
restrictive terms of our indebtedness;

- limit our flexibility in planning for, or reacting to, changes in our
businesses and the industries in which we operate; and

- place us at a competitive disadvantage as compared to our competitors
that have less debt.

We may incur additional indebtedness (public or private) in the future,
either under our existing credit facilities, by issuing debt securities, under
new credit agreements, under joint venture credit agreements, under capital
leases or synthetic leases, on a project finance or other basis, or a
combination of any of these. If we incur additional indebtedness in the future,
it would be under our existing credit facility or under arrangements which may
have terms and conditions at least as restrictive as those contained in our
existing credit facilities and existing indentures. Failure to comply with the
terms and conditions of any existing or future indebtedness would constitute an
event of default. If an event of default occurs, the lenders will have the right
to accelerate the maturity of such indebtedness and foreclose upon the
collateral, if any, securing that indebtedness. If an event of default occurs
under our joint ventures' credit facilities, we may be required to repay amounts
previously distributed to us and our subsidiaries. In addition, if El Paso
Corporation and its subsidiaries no longer own more than 50 percent of our
general partner, that will (1) be an event of default, unless our creditors
agreed otherwise, under our credit facilities and (2) require us to offer to
repurchase all of our senior subordinated notes at 101 percent of their par
value. Any such event could limit our ability to fulfill our obligations under
our debt securities and to make cash distributions to unitholders, including our
minimum quarterly distribution amounts, which could adversely affect the market
price of our securities.

WE MAY NOT BE ABLE TO FULLY EXECUTE OUR GROWTH STRATEGY IF WE ENCOUNTER TIGHT
CAPITAL MARKETS OR INCREASED COMPETITION FOR QUALIFIED ASSETS.

Our strategy contemplates substantial growth through the development and
acquisition of a wide range of midstream and other energy infrastructure assets
while maintaining a strong balance sheet. This strategy includes constructing
and acquiring additional assets and businesses to enhance our ability to compete
effectively, diversify our asset portfolio and, thereby, provide more stable
cash flow. We regularly consider and enter into discussions regarding, and are
currently contemplating, additional potential joint ventures, stand-alone
projects and other transactions that we believe will present opportunities to
realize synergies, expand our role in the energy infrastructure business,
increase our market position and, ultimately, increase distributions to
unitholders.

We will need new capital to finance the future development and acquisition
of assets and businesses. Limitations on our access to capital will impair our
ability to execute this strategy. Expensive capital will limit our ability to
develop or acquire accretive assets. Although we intend to continue to expand
our business, this strategy may require substantial capital, and we may not be
able to raise the necessary funds on satisfactory terms, if at all. For example,
if our common unitholders do not approve the conversion of our outstanding
Series C units into common units when requested and, accordingly our Series C
units receive a preferential distribution rate, issuance of common units will
become a more expensive method of raising capital for us in the future.

In addition, we are experiencing increased competition for the assets we
purchase or contemplate purchasing. Increased competition for a limited pool of
assets could result in our not being the successful bidder more often or our
acquiring assets at a higher relative price than we have paid historically.
Either
61

occurrence would limit our ability to fully execute our growth strategy. Our
ability to execute our growth strategy may impact the market price of our
securities.

OUR GROWTH STRATEGY MAY ADVERSELY AFFECT OUR RESULTS OF OPERATIONS IF WE DO
NOT SUCCESSFULLY INTEGRATE THE BUSINESSES THAT WE ACQUIRE OR IF WE
SUBSTANTIALLY INCREASE OUR INDEBTEDNESS AND CONTINGENT LIABILITIES TO MAKE
ACQUISITIONS.

We may be unable to integrate successfully businesses we acquire. We may
incur substantial expenses, delays or other problems in connection with our
growth strategy that could negatively impact our results of operations.
Moreover, acquisitions and business expansions involve numerous risks,
including:

- difficulties in the assimilation of the operations, technologies,
services and products of the acquired companies or business segments;

- inefficiencies and complexities that can arise because of unfamiliarity
with new assets and the businesses associated with them, including
unfamiliarity with their markets; and

- diversion of the attention of management and other personnel from
day-to-day business, the development or acquisition of new businesses and
other business opportunities.

If consummated, any acquisition or investment would also likely result in
the incurrence of indebtedness and contingent liabilities and an increase in
interest expense and depreciation, depletion and amortization expenses. A
substantial increase in our indebtedness and contingent liabilities could have a
material adverse effect upon our business, as discussed above.

OUR ACTUAL CONSTRUCTION, DEVELOPMENT AND ACQUISITION COSTS COULD EXCEED OUR
FORECAST, AND OUR CASH FLOW FROM CONSTRUCTION AND DEVELOPMENT PROJECTS MAY NOT
BE IMMEDIATE.

Our forecast contemplates significant expenditures for the development,
construction or other acquisition of energy infrastructure assets, including
some construction and development projects with significant technological
challenges. For example, underwater operations, especially those in water depths
in excess of 600 feet, are very expensive and involve much more uncertainty and
risk and if a problem occurs, the solution, if one exists, may be very expensive
and time consuming. Accordingly, there is an increase in the frequency and
amount of cost overruns related to underwater operations, especially in depths
in excess of 600 feet. We may not be able to complete our projects, whether in
deep water or otherwise, at the costs currently estimated. If we experience
material cost overruns, we will have to finance these overruns using one or more
of the following methods:

- using cash from operations;

- delaying other planned projects;

- incurring additional indebtedness; or

- issuing additional debt or equity.

Any or all of these methods may not be available when needed or may adversely
affect our future results of operations.

Our revenues and cash flow may not increase immediately upon the
expenditure of funds on a particular project. For instance, if we build a new
pipeline or platform or expand an existing facility, the design, construction,
development and installation may occur over an extended period of time and we
may not receive any material increase in revenue or cash flow from that project
until after it is placed in service and customers enter into binding
arrangements. If our revenues and cash flow do not increase at projected levels
because of substantial unanticipated delays, we may not meet our obligations as
they become due and we may have to reduce or eliminate distributions to
unitholders.

62

THE FUTURE PERFORMANCE OF OUR ENERGY INFRASTRUCTURE OPERATIONS, AND THUS OUR
ABILITY TO SATISFY OUR DEBT REQUIREMENTS AND MAINTAIN CASH DISTRIBUTIONS,
DEPENDS ON SUCCESSFUL EXPLORATION AND DEVELOPMENT OF ADDITIONAL OIL AND
NATURAL GAS RESERVES BY OTHERS.

The oil, natural gas and other products available to our energy
infrastructure assets are derived from reserves produced from existing wells,
which reserves naturally decline over time. In order to offset this natural
decline, our energy infrastructure assets must access additional reserves.
Additionally, some of the projects we have planned or recently completed,
including our Falcon Nest platform, our Deepwater Gateway joint venture and our
Cameron Highway project, are dependent on reserves that we expect to be produced
from newly discovered properties that producers are currently developing.

Finding and developing new oil and natural gas reserves is very expensive,
especially offshore. The flextrend (water depths of 600 to 1,500 feet) and
deepwater (water depths greater than 1,500 feet) areas of the Gulf of Mexico in
particular will require large capital expenditures by producers for exploration
and development drilling, installing production facilities and constructing
pipeline extensions to reach the new wells. Many economic and business factors
out of our control can adversely affect the decision by any producer to explore
for and develop new reserves. These factors include relatively low oil and
natural gas prices, cost and availability of equipment, regulatory changes,
capital budget limitations or the lack of available capital. Additional
reserves, if discovered, may not be developed in the near future or at all. For
example, because of the level to which hydrocarbon prices declined during 1998
and the first quarter of 1999, overall oil and natural gas activity declined in
relation to prior years. If hydrocarbon prices decline to those levels again or
if capital spending by the energy industry decreases or remains at low levels
for prolonged periods, our results of operations and cash flow could suffer.

WE WILL BE ADVERSELY AFFECTED IF WE CANNOT NEGOTIATE AN EXTENSION OR
REPLACEMENT ON COMMERCIALLY REASONABLE TERMS OF THREE MATERIAL CONTRACTS WHICH
ACCOUNT FOR APPROXIMATELY 70 PERCENT OF THE VOLUME ATTRIBUTABLE TO THE SAN
JUAN GATHERING SYSTEM DURING 2002 AND WHICH EXPIRE BETWEEN 2006 AND 2008.

For the year ended December 31, 2002, approximately 70 percent of the
volume attributable to the San Juan gathering system is derived from contracts
with three major customers, Burlington Resources, Conoco and BP. These contracts
expire in 2008, 2006 and 2006. If we are not able to successfully negotiate
replacement contracts, or if the replacement contracts are on less favorable
terms, the effect on us will be adverse. The following table indicates the
percentage revenue generated by each contract in relation to the indicated
denominator for the year ended December 31, 2002:

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

(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.

WE WILL BE ADVERSELY AFFECTED IF WE CANNOT NEGOTIATE AN EXTENSION OR A
REPLACEMENT ON COMMERCIALLY REASONABLE TERMS OF APPROXIMATELY 900 MILES OF
RIGHTS-OF-WAY UNDERLYING THE SAN JUAN GATHERING SYSTEM.

Approximately 900 miles of the San Juan gathering system benefits from
rights-of-way granted over Native American lands. These rights-of-way expire in
2005. Although these rights-of-way have been renewed in the past, these
rights-of-way may not continue to be renewed on commercially reasonable terms,
or on any terms. If these rights-of-way are not renewed or if the fees for these
rights-of-way increase substantially, the effect on us will be adverse.

63

FLUCTUATIONS IN INTEREST RATES COULD ADVERSELY AFFECT OUR BUSINESS.

In addition to our exposure to commodity prices, we also have exposure to
movements in interest rates. The interest rates on some of our indebtedness,
like our senior subordinated notes, are fixed and the interest rates on some of
our other indebtedness, like our credit facility and senior secured acquisition
term loan, EPN Holding term credit facility and the credit facilities of our
joint ventures, are variable. Our results of operations and our cash flow, as
well as our access to future capital and our ability to fund our growth
strategy, could be adversely affected by significant increases or decreases in
interest rates.

OUR EPN TEXAS FRACTIONATION FACILITIES ARE DEDICATED TO A SINGLE CUSTOMER, THE
LOSS OF WHICH COULD ADVERSELY AFFECT US.

In connection with our acquisition of our EPN Texas fractionation
facilities, we entered into a 20-year fee-based transportation and fractionation
agreement and have dedicated 100 percent of the capacity of our fractionation
facilities to a subsidiary of El Paso Corporation. In that 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 produced at the EPN Texas fractionation facilities.

Our operations are likely to be adversely affected if this arrangement is
terminated or if El Paso Field Services does not deliver enough NGL to us to
ensure that we can maintain a profitable utilization rate or does not fully
perform its obligations under the agreement.

FLUCTUATIONS IN ENERGY COMMODITY PRICES COULD ADVERSELY AFFECT OUR BUSINESS.

Oil, natural gas and other petroleum products prices are volatile and could
have an adverse effect on a portion of our revenues and cash flow. Although our
strategy involves mitigating our exposure to the volatility in commodity prices,
primarily by focusing on fee-based services, all segments of our operations are
somewhat affected by price reductions and some of our segments are significantly
affected by price reductions. Price reductions can materially reduce the level
of oil and natural gas exploration, pipeline volumes, production and development
operations, which provide reserves to replace those that are produced over time.
In addition, some of our operations, like production, processing and
fractionation, are very sensitive to price declines.

Natural gas pipelines and plants -- Price decreases could have an adverse
effect on the discovery and development of replacement reserves and on the
results of operations of our San Juan natural gas gathering system, our Chaco
plant and our Indian Basin plant.

Currently, the primary consequence of commodity price reductions to our
pipeline and platform operations is the risk that less replacement reserves will
be discovered and developed as a result of a long-term decline in prices.
Although the majority of our pipeline and platform operations involve fee-based
arrangements for gathering, transporting and handling reserves that are
dedicated to the facilities for the life of the reserves, some of our pipelines
can be dramatically affected by a reduction in commodity prices because those
pipelines purchase and resell the commodity.

The financial results from our San Juan natural gas gathering system, our
Chaco plant and our Indian Basin plant can be dramatically affected by a
reduction in, or the volatility of, 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
natural gas price index. In addition, the San Juan gathering system provides
aggregating and bundling services -- in which it purchases gas at the wellhead
and resells gas in the open market -- for some smaller producers, which account
for less than five percent of the volumes on that system.

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Prices for natural gas, NGL and NGL components can fluctuate in response to
changes in supply, market uncertainty and a variety of additional factors that
are beyond our control. Contemporaneously with the November 2002 San Juan assets
acquisition, our tolling arrangement with a subsidiary of El Paso Corporation
relating to the Chaco plant was terminated. Accordingly, a substantial portion
of our Chaco plant processing arrangements are now exposed to commodity price
risk -- specifically prices for NGL. Substantially all of our revenues for
natural gas processing services at the Chaco plant and Indian Basin plant will
fluctuate directly with the monthly price of NGL.

Utilization rates in the processing industry can fluctuate dramatically
from month to month, depending on the needs of producers. The average
utilization rate for the Chaco processing plant for the calendar years 2002,
2001, and 2000 was 90 percent, 89 percent and 91 percent. The average
utilization rate for the Indian Basin processing plant for the calendar years
2002, 2001 and 2000 was 93 percent, 93 percent and 82 percent.

Natural gas storage -- Natural gas price stability could have an adverse
effect on revenue and cash flow from our storage assets.

Prices for natural gas have historically been seasonal and volatile, which
has enhanced demand for our storage services. The storage business has benefited
from large price swings resulting from seasonal price sensitivity through
increased withdrawal charges and demand for non-storage hub services. However,
the market for natural gas may not continue to experience volatility and
seasonal price sensitivity in the future at the levels previously seen. If
volatility and seasonality in the natural gas industry decrease, because of
increased storage capacity throughout the pipeline grid, increased production
capacity or otherwise, the demand for our storage services and, therefore, the
prices that we will be able to charge for those services may decline.

Oil and NGL logistics -- The fractionation business is cyclical and is
dependent in part upon the spreads between prices for natural gas, NGL and
petroleum products.

Since our fractionation facilities provide fee-based services, for which we
receive a fixed fee for each unit of NGL we fractionate, our fractionation
operations are not directly affected by fluctuations in prices for natural gas,
NGL and NGL components. However, if the spread between prices for natural gas,
NGL and NGL components do not provide sufficient profits to natural gas
producers, then those producers may decide not to process their natural gas or
fractionate their NGL, or to process less natural gas or fractionate less NGL.
This could decrease the volumes to our processing and fractionation facilities
and, accordingly, negatively affect our operational results. In many cases,
processing and fractionating is profitable only when the producer can receive
more net proceeds by physically separating the natural gas from the NGL and
separating the NGL components from the NGL and selling those products than it
would receive by merely selling the raw natural gas stream. The spread between
the prices for natural gas and NGL is greatest when the demand for NGL increases
for use in petrochemical and refinery feedstock. If, and when, this spread
becomes too narrow to justify the costs, producers have the option to sell the
raw natural gas stream rather than process and fractionate. In such a case, our
processing or fractionation facilities or both will be underutilized. Although
our fixed fee-based arrangements limit the direct effects of decreases in
commodity prices on our fractionation operations, those arrangements also cause
us to forego any benefits we would otherwise experience if commodity prices were
to increase.

Utilization rates in the fractionation industry can fluctuate dramatically
from month to month, depending on the needs of producers. The monthly
utilization rate for our fractionation facilities during the 12 months ending
December 31, 2002 was as low as 58 percent and as high as 82 percent. However,
our average annual utilization rate for our fractionation facilities for 2002,
2001 and 2000 were 74 percent, 73 percent and 89 percent.

65

Oil and natural gas production -- Price and volume volatility is substantially
out of our control and could have an adverse effect on revenues and cash flow
from our producing oil and natural gas properties.

We have exposure to movements in commodity prices relating to our oil and
natural gas production, which we partially hedge from time to time using
financial derivative instruments. Our results of operations and our cash flow
could be materially adversely affected by factors we cannot control, including:

- fluctuations in prices of oil and natural gas;

- future operating costs; and

- risks incident to the operation of oil and natural gas wells.

ENVIRONMENTAL COSTS AND LIABILITIES AND CHANGING ENVIRONMENTAL REGULATION
COULD AFFECT OUR CASH FLOW.

Our operations are subject to extensive federal, state and local regulatory
requirements relating to environmental affairs, health and safety, waste
management and chemical and petroleum products. Governmental authorities have
the power to enforce compliance with applicable regulations and permits and to
subject violators to civil and criminal penalties, including fines, injunctions
or both. Third parties may also have the right to pursue legal actions to
enforce compliance. We will make expenditures in connection with environmental
matters as part of normal capital expenditure programs. However, future
environmental law developments, such as stricter laws, regulations, permits or
enforcement policies, could significantly increase some costs of our operations,
including the handling, manufacture, use, emission or disposal of substances and
wastes. Moreover, as with other companies engaged in similar or related
businesses, our operations always have some risk of environmental costs and
liabilities because we handle petroleum products.

OUR USE OF DERIVATIVE FINANCIAL INSTRUMENTS COULD RESULT IN FINANCIAL LOSSES.

We use financial derivative instruments and other hedging mechanisms from
time to time to limit a portion of the adverse effects resulting from changes in
oil and natural gas commodity prices and interest rates, although there are
times when we do not have any hedging mechanisms in place. To the extent we
hedge our commodity price exposure and interest rate exposure, we forego the
benefits we would otherwise experience if commodity prices were to increase or
interest rates were to decrease. In addition, we could experience losses
resulting from our hedging and other derivative positions. Such losses could
occur under various circumstances, including if our counterparty does not
perform its obligations under the hedge arrangement, our hedge is imperfect, or
our hedging policies and procedures are not followed.

WE MAY BE ADVERSELY AFFECTED BY EL PASO CORPORATION'S INTENTIONS OF EXITING
THE ENERGY TRADING BUSINESS.

El Paso Corporation announced on November 8, 2002 its intentions to exit
the energy trading business. During the year ended December 31, 2002,
transportation and storage contracts with El Paso Merchant Energy North America
Company accounted for $33 million in revenue. If El Paso Merchant Energy North
America abandons this contract and we are unable to successfully negotiate
replacement contracts with unaffiliated parties, or if the replacement contracts
are on less favorable terms, the effect on us will be adverse.

WE WILL FACE COMPETITION FROM THIRD PARTIES TO GATHER, TRANSPORT, PROCESS,
FRACTIONATE, STORE OR OTHERWISE HANDLE OIL, NATURAL GAS AND OTHER PETROLEUM
PRODUCTS.

Even if reserves exist in the areas accessed by our facilities and are
ultimately produced, we may not be chosen by the producers to gather, transport,
process, fractionate, store or otherwise handle any of these reserves. We
compete with others, including producers of oil and natural gas, for any such
production on the basis of many factors, including:

- geographic proximity to the production;

- costs of connection;

66

- available capacity;

- rates; and

- access to markets.

FERC REGULATION AND A CHANGING REGULATORY ENVIRONMENT COULD AFFECT OUR CASH
FLOW.

The FERC extensively regulates certain of our energy infrastructure assets.
This regulation extends to such matters as:

- rate structures;

- rates of return on equity;

- recovery of costs;

- the services that our regulated assets are permitted to perform;

- the acquisition, construction and disposition of assets; and

- to an extent, the level of competition in that regulated industry.

In September 2001, the FERC issued a Notice of Proposed Rulemaking (NOPR)
that proposes to apply the standards of conduct governing the relationship
between interstate pipelines and marketing affiliates to all energy affiliates.
Since our HIOS natural gas pipeline and Petal natural gas storage facilities are
interstate facilities as defined by the Natural Gas Act, the proposed
regulations, if adopted by FERC, would dictate how HIOS and Petal conduct
business and interact with all energy affiliates of El Paso Corporation and us.
In December 2001, we filed comments with the FERC addressing our concerns with
the proposed rules. A public hearing was held in May 2002, providing an
opportunity to comment further on the NOPR. Following the conference, additional
comments were filed by us. At this time, we cannot predict the outcome of the
NOPR, but adoption of the regulations in the form proposed would, at a minimum,
place additional administrative and operational burdens on us.

If the standards of conduct NOPR is adopted by the FERC, we will be
required to functionally separate our HIOS and Petal interstate facilities from
our other entities. Under the proposed rule, we would be required to dedicate
employees to manage and operate our interstate facilities independently from our
other non-jurisdictional facilities. This employee group would be required to
function independently and would be prohibited from communicating non-public
transportation information to affiliates. Separate office facilities and systems
would be necessary because of the requirement to restrict affiliate access to
interstate transportation information. The NOPR also limits the sharing of
employees and officers with non-regulated entities. Because of the loss of
synergies and shared employee restrictions, a disposition of the interstate
facilities may be necessary for us to effectively comply with the rule.

In July 2002, the FERC issued a Notice of Inquiry (NOI) that seeks comments
regarding its 1996 policy of permitting pipelines to enter into negotiated rate
transactions. The FERC is now reviewing whether negotiated rates should be
capped, whether or not the "recourse rate" (a cost of service based rate)
continues to safeguard against a pipeline exercising market power, as well as
other issues related to negotiated rate programs. At this time, we cannot
predict the outcome of this NOI.

In August 2002, the FERC issued a NOPR requiring that all cash management
or money pool arrangements between a FERC regulated subsidiary and a non-FERC
regulated parent must be in writing, and set forth: the duties and
responsibilities of cash management participants and administrators; the methods
of calculating interest and for allocating interest income and expenses; and the
restrictions on deposits or borrowings by money pool members. The NOPR also
requires specified documentation for all deposits into, borrowings from,
interest income from, and interest expenses related to, these arrangements.
Finally, the NOPR proposes that as a condition of participating in a cash
management or money pool arrangement, the FERC regulated entity must maintain a
minimum proprietary capital balance of 30 percent, and the FERC

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regulated entity and its parent must maintain investment grade credit ratings.
In August 2002, comments were filed. The FERC held a public conference in
September 2002, to discuss the issues raised in the comments. Representatives of
companies from the gas and electric industries participated on a panel and
uniformly agreed that the proposed regulations should be revised substantially
and that the proposed capital balance and investment grade credit rating
requirements would be excessive. At this time, we cannot predict the outcome of
this NOPR.

Also in August 2002, FERC's Chief Accountant issued an Accounting Release,
to be effective immediately, providing guidance on how companies should account
for money pool arrangements and the types of documentation that should be
maintained for these arrangements. However, the Accounting Release did not
address the proposed requirements that the FERC regulated entity maintain a
minimum proprietary capital balance of 30 percent and that the entity and its
parent have investment grade credit ratings. Requests for rehearing were filed
in August 2002. The FERC has not yet acted on rehearing requests.

If the cash management NOPR is adopted by the FERC, our HIOS and Petal
interstate facilities will no longer be permitted to participate in a money pool
or cash management program. As a result, more frequent distributions or equity
contributions may be needed in anticipation of monthly cash flow requirements
for those interstate facilities. Also, separate credit facilities and resources
may be required to support the capital and day-to-day activities for the
interstate facilities separate from other of our subsidiaries and our primary
bank accounts.

In April 2002, FERC and the Department of Transportation, Office of
Pipeline Safety convened a technical conference to discuss how to clarify,
expedite, and streamline permitting and approvals for interstate pipeline
reconstruction in the event of disaster, whether natural or otherwise. In
January 2003, FERC issued a NOPR proposing (1) expand the scope of construction
activities authorized under a pipeline's blanket certificate to allow
replacement of mainline facilities; (2) authorize a pipeline to commence
reconstruction of the affected system without a waiting period; and (3)
authorize automatic approval of construction that would be above the normal cost
ceiling. Comments on the NOPR were due on February 27, 2003. At this time we
cannot predict the outcome of this rulemaking.

In January, 2003, the U.S. Department of Transportation issued a NOPR
proposing to establish a rule requiring pipeline operators to develop integrity
management programs to comprehensively evaluate their pipelines, and take
measures to protect pipeline segments located in what the notice refers to as
"high consequence areas." The proposed rule resulted from the enactment of the
Pipeline Safety Improvement Act of 2002, a new bill signed into law in December
2002. We intend to submit comments on the NOPR, which are due on March 31, 2003.
At this time, we cannot predict the outcome of this rulemaking.

Given the extent of this regulation, the extensive changes in FERC policy
over the last several years, the evolving nature of regulation and the
possibility for additional changes, the current regulatory regime may change and
affect our financial position, results of operations or cash flows.

A NATURAL DISASTER, CATASTROPHE OR OTHER INTERRUPTION EVENT INVOLVING US COULD
RESULT IN SEVERE PERSONAL INJURY, PROPERTY DAMAGE AND ENVIRONMENTAL DAMAGE,
WHICH COULD CURTAIL OUR OPERATIONS AND OTHERWISE ADVERSELY AFFECT OUR CASH
FLOW.

Some of our operations involve higher risks of severe personal injury,
property damage and environmental damage, any of which could curtail our
operations and otherwise expose us to liability and adversely affect our cash
flow. For example, our natural gas facilities operate at high pressures,
sometimes in excess of 1,100 pounds per square inch. We also operate oil and
natural gas facilities located underwater in the Gulf of Mexico, which can
involve complexities, such as extreme water pressure. Virtually all of our
operations are exposed to the elements, including hurricanes, tornadoes, storms,
floods and earthquakes.

If one or more facilities that are owned by us or that deliver oil, natural
gas or other products to us is damaged or otherwise affected by severe weather
or any other disaster, accident, catastrophe or event, our operations could be
significantly interrupted. Similar interruptions could result from damage to
production or other facilities that supply our facilities or other stoppages
arising from factors beyond our control. These interruptions might involve
significant damage to people, property or the environment, and repairs might
take
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from a week or less for a minor incident to six months or more for a major
interruption. Additionally, some of our storage contracts obligate us to
indemnify our customers for any damage or injury occurring during the period in
which the customers' natural gas is in our possession. Any event that interrupts
the fees generated by our energy infrastructure assets, or which causes us to
make significant expenditures not covered by insurance, could reduce our cash
available for paying our interest obligations as well as unitholder
distributions and, accordingly, adversely impact the market price of our
securities. Additionally, the proceeds of any property and business interruption
insurance maintained by us may not be paid in a timely manner or be in an amount
sufficient to meet our needs if such an event were to occur, and we may not be
able to renew it or obtain other desirable insurance on commercially reasonable
terms, if at all.

ARTHUR ANDERSEN LLP, THE PUBLIC ACCOUNTANTS THAT AUDITED THE 2000 FINANCIAL
STATEMENTS OF OUR JOINT VENTURE POSEIDON OIL PIPELINE COMPANY, L.L.C., HAS
BEEN CONVICTED OF A FELONY, WHICH MAY ADVERSELY AFFECT THE ABILITY OF ARTHUR
ANDERSEN LLP TO SATISFY ANY CLAIMS THAT MAY ARISE OUT OF ARTHUR ANDERSEN LLP'S
AUDIT OF POSEIDON'S FINANCIAL STATEMENTS. IN ADDITION, ARTHUR ANDERSEN LLP HAS
NOT CONSENTED TO THE USE OF THEIR OPINION IN THIS FILING. BECAUSE OF THIS,
YOUR ABILITY TO EVER CLAIM AGAINST ARTHUR ANDERSEN LLP MAY BE LIMITED.

Arthur Andersen LLP is the independent public accountant that audited the
financial statements of our Poseidon joint venture for the year ended December
31, 2000. Arthur Andersen LLP was recently convicted of obstruction of justice
in connection with the U.S. government's investigation of Enron Corp. Events
arising out of this conviction may adversely affect the ability of Arthur
Andersen LLP to satisfy any claims that may arise out of Arthur Andersen LLP's
audits of Poseidon's financial statements. Additionally, because the personnel
responsible for the audit of Poseidon's financial statements are no longer
employed by Arthur Andersen LLP, we have not received Arthur Andersen LLP's
consent with respect to the inclusion of those financial statements and the
related audit report; accordingly, if those financial statements are inaccurate,
your ability to make a claim against Arthur Andersen LLP may be limited or
prohibited.

CONFLICTS OF INTEREST RISKS

EL PASO CORPORATION AND ITS SUBSIDIARIES HAVE CONFLICTS OF INTEREST WITH US
AND, ACCORDINGLY, YOU.

We have potential and existing conflicts of interest with El Paso
Corporation and its affiliates in four general areas:

- we have historically entered into transactions with each other, including
some relating to operating and managing assets, acquiring and selling
assets, and performing services;

- we share personnel, assets, systems and other resources;

- from time to time, we compete for business and customers; and

- from time to time, we both may have an interest in acquiring the same
asset, business or other business opportunity.

We expect to continue to enter into transactions and other activities with
El Paso Corporation and its subsidiaries because of the businesses and areas in
which we and El Paso Corporation currently operate, as well as those in which we
plan to operate in the future. Some more recent transactions in which we, on the
one hand, and El Paso Corporation and its subsidiaries, on the other hand, had a
conflict of interest include:

- in November 2002, we acquired the San Juan assets from El Paso
Corporation for approximately $782 million, net $766 million adjusted for
capital expenditures and actual working capital acquired;

- in April 2002, we acquired the EPN Holding assets from El Paso
Corporation for approximately $735 million of net consideration; and

- pursuant to a general and administrative services agreement, subsidiaries
of El Paso Corporation provide us administrative, operational and other
services.

In addition, we and El Paso Corporation and its subsidiaries share and,
therefore will compete for, the time and effort of El Paso Corporation personnel
who provide services to us, including directors, officers and other personnel.
Personnel of the general partner and its subsidiaries do not, and will not be
required to, spend

69

any specified percentage or amount of time on our business. Since these shared
personnel function as both our representatives and those of El Paso Corporation
and its subsidiaries, conflicts of interest could arise between El Paso
Corporation and its subsidiaries, on the one hand, and us and our unitholders,
on the other. Additionally, some of these personnel own and have been awarded
from time to time financial shares, or options to purchase shares, of El Paso
Corporation; accordingly, their financial interests may not always be aligned
completely with ours or those of our limited partners.

Some other situations in which an actual or potential conflict of interest
arises between us, on the one hand, and our general partner or its affiliates
(including El Paso Corporation), on the other hand, and there is a benefit to
our general partner or its subsidiaries in which neither us nor our limited
partners will share include:

- compensation paid to the general partner, which includes incentive
distributions and reimbursements for reasonable general and
administrative expenses;

- payments to the general partner and its affiliates for any services
rendered to us or on our behalf;

- our general partner's determination of which direct and indirect costs we
must reimburse; and

- our general partner's determination to establish cash reserves under
certain circumstances and thereby decrease cash available for
distributions to unitholders.

In addition, El Paso Corporation's beneficial ownership interest in our
outstanding partnership interests could have a substantial effect on the outcome
of some actions requiring partner approval. Accordingly, subject to legal
requirements, El Paso Corporation makes the final determination regarding how
any particular conflict of interest is resolved.

The interests of El Paso Corporation and its subsidiaries may not always be
aligned with our interest, and, accordingly, they may not always act in your
best interest. El Paso Corporation is neither contractually nor legally bound to
use us as its primary vehicle for growth and development of midstream energy
assets, and may reconsider at any time, without notice. Further, El Paso
Corporation is not required to pursue any business strategy that will favor our
business opportunities over the business opportunities of El Paso Corporation or
any of its affiliates. El Paso Corporation and its subsidiaries (many of which
are wholly owned) operate in some of the same lines of business and in some of
the same geographic areas in which we operate.

BECAUSE WE DEPEND UPON EL PASO CORPORATION AND ITS SUBSIDIARIES FOR EMPLOYEES
TO MANAGE OUR BUSINESS AND AFFAIRS, A DECREASE IN THE AVAILABILITY OF
EMPLOYEES FROM EL PASO CORPORATION AND ITS AFFILIATES COULD ADVERSELY AFFECT
US.

We have no employees. In managing our business and affairs, our general
partner relies on employees of El Paso Corporation and its affiliates under a
general and administrative services agreement between our general partner, on
one hand, and subsidiaries of El Paso Corporation, on the other hand. Those
employees will act on behalf of and as agents for us. A decrease in the
availability of employees from El Paso Corporation and its affiliates could
adversely affect us. Although this arrangement has worked well for us in the
past and continues to work well for us, in accordance with our recently
accounted Independence Initiatives, we are evaluating the direct employment of
the personnel who manage the day-to-day operations of our assets.

DUE TO OUR SIGNIFICANT RELATIONSHIPS WITH EL PASO CORPORATION, ADVERSE
DEVELOPMENTS CONCERNING EL PASO CORPORATION COULD ADVERSELY AFFECT US, EVEN IF
WE HAVE NOT SUFFERED ANY SIMILAR DEVELOPMENTS.

Through its subsidiaries, El Paso Corporation owns 100 percent of our
general partner and has historically, with its affiliates, employed the
personnel who operate our businesses. El Paso Corporation is a significant
stakeholder in our limited partner interests, and as with many other large
energy companies, is a significant customer of ours. The outstanding senior
unsecured indebtedness of El Paso Corporation has been

70

downgraded to below investment grade, at least in part, as a result of the
outlook for the consolidated business of El Paso Corporation and its need for
liquidity. In the event that El Paso Corporation's liquidity needs are not
satisfied, El Paso Corporation could be forced to seek protection from its
creditors in bankruptcy. Although we are making efforts to implement new
procedures and other mechanisms to better balance the risks and rewards of our
significant relationships with El Paso Corporation and its affiliates, if El
Paso Corporation continues to suffer financial stress, we may be adversely
affected, even if we have not suffered any similar developments.

OUR GENERAL PARTNER AND ITS AFFILIATES MAY SELL UNITS OR OTHER LIMITED PARTNER
INTERESTS IN THE TRADING MARKET, WHICH COULD REDUCE THE MARKET PRICE OF COMMON
UNITS.

As of the date of this annual report, our general partner and its
affiliates own 11,674,275 common units and 10,937,500 Series C units that may
ultimately be converted into common units. In the future, they may acquire
additional interest or dispose of some or all of their interest. If they were to
dispose of a substantial portion of their interest in the trading markets, it
could reduce the market price of common units. Our partnership agreement, and
other agreements to which we are party, allow our general partner and certain of
its subsidiaries to cause us to register for sale the partnership interests held
by such persons, including common units. These registration rights allow our
general partner and its subsidiaries to request registration of those
partnership interests and to include any of those securities in a registration
of other capital securities by us.

OUR PARTNERSHIP AGREEMENT PURPORTS TO LIMIT OUR GENERAL PARTNER'S FIDUCIARY
DUTIES AND CERTAIN OTHER OBLIGATIONS RELATING TO US.

Although our general partner owes fiduciary duties to us and will be liable
for all our debts, other than non-recourse debts, to the extent not paid by us,
certain provisions of our partnership agreement contain exculpatory language
purporting to limit the liability of our general partner to us and unitholders.
For example, the partnership agreement provides that:

- borrowings of money by us, or the approval thereof by our general
partner, will not constitute a breach of any duty of our general partner
to us or you whether or not the purpose or effect of the borrowing is to
permit distributions on our limited partner interests or to result in or
increase incentive distributions to our general partner;

- any action taken by our general partner consistent with the standards of
reasonable discretion set forth in certain definitions in our partnership
agreement will be deemed not to breach any duty of our general partner to
us or to unitholders; and

- in the absence of bad faith by our general partner, the resolution of
conflicts of interest by our general partner will not constitute a breach
of the partnership agreement or a breach of any standard of care or duty.

Provisions of the partnership agreement also purport to modify the
fiduciary duty standards to which our general partner would otherwise be subject
under Delaware law, under which a general partner owes its limited partners the
highest duties of good faith, fairness and loyalty. The duty of loyalty would
generally prohibit our general partner from taking any action or engaging in any
transaction as to which it had a conflict of interest. The partnership agreement
permits our general partner to exercise the discretion and authority granted to
it in that agreement in managing us and in conducting its retained operations,
so long as its actions are not inconsistent with our interests. Our general
partner and its officers and directors may not be liable to us or to unitholders
for certain actions or omissions which might otherwise be deemed to be a breach
of fiduciary duty under Delaware or other applicable state law. Further, the
partnership agreement requires us to indemnify our general partner to the
fullest extent permitted by law, which indemnification, in light of the
exculpatory provisions in the partnership agreement, could result in us
indemnifying our general partner for negligent acts.

71

CASH RESERVES, EXPENDITURES AND OTHER MATTERS WITHIN THE DISCRETION OF OUR
GENERAL PARTNER MAY AFFECT DISTRIBUTIONS TO UNITHOLDERS AND RESERVES FOR DEBT
SERVICE.

Our general partner has broad discretion to make cash expenditures and to
establish and make additions to cash reserves for any proper partnership
purpose, including reserves for the purpose of:

- providing for future operating and capital expenditures;

- providing for debt service;

- providing funds for up to the next four quarterly distributions;

- providing funds to redeem or otherwise repurchase our outstanding debt or
equity;

- stabilizing distributions of cash to capital security holders;

- complying with the terms of any agreement or obligation of ours; and

- providing for a discretionary reserve amount.

The timing and amount of additions to discretionary reserves could
significantly reduce potential distributions that certain unitholders could
receive or ultimately affect who gets the distribution. The reduction or
elimination of a previously established reserve in a particular quarter will
result in a higher level of cash available for distribution than would otherwise
be available in such quarter. Depending upon the resulting level of cash
available for distribution, our general partner may receive incentive
distributions which it would not have otherwise received. Thus, our general
partner could have a conflict of interest in determining the amount and timing
of any increases or decreases in reserves. Our general partner receives the
following compensation:

- distributions in respect of its general and limited partner interests in
us;

- incentive distributions to the extent that available cash exceeds
specified target levels that are over $0.325 per unit per quarter; and

- reimbursements for reasonable general and administrative expenses, and
other reasonable expenses, incurred by our general partner and its
subsidiaries for or on our behalf.

Our partnership agreement was not, and many of the other agreements,
contracts and arrangements between us, on the one hand, and our general partner
and its subsidiaries, on the other hand, were not and may not be the result of
arm's-length negotiations and, as a result, those agreements may not be as
profitable or advantageous to us and may produce a lower distribution for our
unitholders than those negotiated at arm's-length.

In addition, increases to reserves (other than the discretionary reserve
amount provided for in the partnership agreement) will reduce our cash from
operations, which under certain limited circumstances could result in certain
distributions to be attributable to interim capital transactions rather than to
cash from operations. If a cash distribution was attributable to an interim
capital transaction, (i) 99 percent of the distribution would be made pro rata
to all limited partners, including the Series B preference unitholders and
Series C unitholders, and (ii) the distribution would be deemed a return of a
portion of an investor's investment in his partnership interest and would reduce
each of our general partner's target distribution levels proportionately.

RISKS INHERENT IN AN INVESTMENT IN OUR SECURITIES

UNITHOLDERS HAVE LIMITED VOTING RIGHTS AND DO NOT CONTROL OUR GENERAL PARTNER.

Unlike the holder of capital stock in a corporation, unitholders have
limited voting rights on matters affecting our business. Our general partner,
whose directors unitholders do not elect, manages our activities. Our
unitholders will have no right to elect our general partner on an annual or any
other continuing basis. If our general partner voluntarily withdraws, however,
the holders of a majority of our outstanding limited partner interests
(excluding for purposes of such determination interests owned by the withdrawing
general partner and its affiliates) may elect its successor.
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Our general partner may not be removed as our general partner except upon
approval by the affirmative vote of the holders of at least 55 percent of our
outstanding limited partner interests (including limited partner interests owned
by our general partner and its affiliates), subject to the satisfaction of
certain conditions. Any removal of our general partner is not effective until
the holders of a majority of our outstanding limited partner interests approve a
successor general partner. Before the holders of outstanding limited partner
interests may remove our general partner, they must receive an opinion of
counsel that:

- such action will not result in the loss of limited liability of any
limited partner or of any member of any of our subsidiaries or cause us
or any of our subsidiaries to be taxable as a corporation or to be
treated as an association taxable as a corporation for federal income tax
purposes; and

- all required consents by any regulatory authorities have been obtained.

If our general partner were to withdraw or be removed as our general
partner, that would effectively result in its concurrent withdrawal or removal
as the manager of our subsidiaries.

WE MAY ISSUE ADDITIONAL SECURITIES, WHICH WILL DILUTE INTERESTS OF UNITHOLDERS
AND MAY ADVERSELY EFFECT THEIR VOTING POWER.

We can issue additional common units, preference units and other capital
securities representing limited partner interests, including securities with
rights to distributions and allocations or in liquidation equal or superior to
the equity securities held by existing unitholders, for any amount and on any
terms and conditions established by our general partner. For example, in 2002,
we issued 4,243,435 additional common units and 10,937,500 Series C units, which
may ultimately convert into common units. If we issue more limited partner
interests, it will reduce each common unitholder's proportionate ownership
interest in us. This could cause the market price of the common units to fall
and reduce the cash distributions paid to our limited partners. Further, we have
the ability to issue partnership interests with voting rights superior to the
unitholders. If we issue any such securities, it could adversely affect the
voting power of the common units.

OUR GENERAL PARTNER HAS ANTI-DILUTION RIGHTS.

Whenever we issue equity securities to any person other than our general
partner and its affiliates, our general partner and its affiliates have the
right to purchase an additional amount of those equity securities on the same
terms as they are issued to the other purchasers. This allows our general
partner and its affiliates to maintain their percentage partnership interest in
us. No other unitholder has a similar right. Therefore, only our general partner
may protect itself against dilution caused by the issuance of additional equity
securities.

UNITHOLDERS MAY NOT HAVE LIMITED LIABILITY IN THE CIRCUMSTANCES DESCRIBED
BELOW, INCLUDING POTENTIALLY HAVING LIABILITY FOR THE RETURN OF WRONGFUL
DISTRIBUTIONS.

We operate businesses in Alabama, Colorado, Louisiana, Mississippi, New
Mexico and Texas and plan to expand into more states. In some states (but not
any of the states in which we currently do business), the limitations on the
liability of limited partners for the obligations of a limited partnership have
not been clearly established. To the extent we conduct business in one of those
states, a unitholder might be held liable for our obligations as if it was a
general partner if:

- a court or government agency determined that we had not complied with
that state's partnership statute; or

- our unitholders' rights to act together to remove or replace our general
partner or take other actions under our partnership agreement were to
constitute "control" of our business under that state's partnership
statute.

A unitholder will not be liable for assessments in addition to its initial
capital investment in any of our capital securities representing limited
partnership interests. However, a unitholder may be required to repay to us any
amounts wrongfully returned or distributed to it under some circumstances. Under
Delaware law, we may not make a distribution to unitholders if the distribution
causes our liabilities (other than liabilities to

73

partners on account of their partnership interests and nonrecourse liabilities)
to exceed the fair value of our assets. Delaware law provides that a limited
partner who receives such a distribution and knew at the time of the
distribution that the distribution violated the law will be liable to the
limited partnership for the amount of the distribution for three years from the
date of the distribution.

OUR GENERAL PARTNER HAS A LIMITED CALL RIGHT THAT MAY REQUIRE UNITHOLDERS TO
SELL THEIR LIMITED PARTNER INTERESTS AT AN UNDESIRABLE TIME OR PRICE.

If at any time our general partner and its affiliates hold 85 percent or
more of any class or series of our issued and outstanding limited partner
interests, our general partner will have the right to purchase all, but not less
than all, of the outstanding securities of that class or series held by
nonaffiliates. This purchase would take place as of a record date which would be
selected by our general partner, on at least 30 but not more than 60 days'
notice. Our general partner may assign and transfer this call right to any of
its affiliates or to us. If our general partner (or its assignee) exercises this
call right, it must purchase the securities at the higher of (i) the highest
cash price paid by our general partner or its affiliates for any unit or other
limited partner interest of such class purchased within the 90 days preceding
the date our general partner mails notice of the election to call the units or
other limited partner interests or (ii) the average of the last reported sales
price per unit or other limited partner interest of such class over the 20
trading days preceding the date five days before our general partner mails such
notice. Accordingly, under certain circumstances unitholders may be required to
sell their limited partner interests against their will and the price they
receive for those securities may be less than they would like to receive.

OUR EXISTING UNITS ARE, AND POTENTIALLY ANY LIMITED PARTNER INTERESTS WE ISSUE
IN THE FUTURE WILL BE, SUBJECT TO RESTRICTIONS ON TRANSFER.

All purchasers of our existing units, and potentially any purchasers of
limited partner interests we issue in the future, who wish to become holders of
record and receive cash distributions must deliver an executed transfer
application in which the purchaser or transferee must certify that, among other
things, he, she or it agrees to be bound by our partnership agreement and is
eligible to purchase our securities. A person purchasing our existing units, or
possibly limited partner interests we issue in the future, who does not execute
a transfer application and certify that the purchaser is eligible to purchase
those securities acquires no rights in those securities other than the right to
resell those securities. Further, our general partner may request each record
holder to furnish certain information, including that holder's nationality,
citizenship or other related status. An investor who is not a U.S. resident may
not be eligible to become a record holder or one of our limited partners if that
investor's ownership would subject us to the risk of cancellation or forfeiture
of any of our assets under any federal, state or local law or regulation. If the
record holder fails to furnish the information or if our general partner
determines, on the basis of the information furnished by the holder in response
to the request, that such holder is not qualified to become one of our limited
partners, our general partner may be substituted as a holder for the record
holder, who will then be treated as a non-citizen assignee, and we will have the
right to redeem those securities held by the record holder.

WE MAY NOT BE ABLE TO SATISFY OUR OBLIGATION TO REPURCHASE DEBT SECURITIES
UPON A CHANGE OF CONTROL.

Upon a change of control (among other things, the acquisition of 50 percent
or more of El Paso Corporation's voting stock, or if El Paso Corporation and its
subsidiaries no longer own more than 50 percent of our general partner, or the
sale of all or substantially all of our assets), unless our creditors agreed
otherwise, we would be required to repay the amounts outstanding under our
credit facilities and to offer to repurchase our outstanding senior subordinated
notes at 101 percent of the principal amount, plus accrued and unpaid interest
to the date of repurchase. We may not have sufficient funds available or be
permitted by our other debt instruments to fulfill these obligations upon the
occurrence of a change of control. We have publicly disclosed our efforts to
further distinguish ourselves from El Paso Corporation. As a result of this
announcement, and investors' perception that general partner investments are
trading at lower than historical valuations, various parties have expressed an
interest in purchasing all or a portion of our general partner. We have been
entrusted by the owner of our general partner to meet with a limited number of
such investors to

74

gauge the level of their interest and will report back to El Paso Corporation on
the outcomes of these meetings. El Paso Corporation has the sole responsibility
of determining the ultimate ownership status of the general partner interest. We
acknowledge that we are meeting with parties interested in acquiring an equity
stake in the general partner but cannot confirm that such interest will result
in firm proposals or, if such firm proposals are received, that El Paso
Corporation will pursue such proposals.

RISKS RELATED TO OUR LEGAL STRUCTURE

THE INTERRUPTION OF DISTRIBUTIONS TO US FROM OUR SUBSIDIARIES AND JOINT
VENTURES MAY AFFECT OUR ABILITY TO MAKE PAYMENTS ON OUR DEBT SECURITIES OR
CASH DISTRIBUTIONS TO OUR UNITHOLDERS.

We are a holding company. As such, our primary assets are the capital stock
and other equity interests in our subsidiaries and joint ventures. Consequently,
our ability to fund our commitments (including payments on our debt securities)
and to make cash distributions depends upon the earnings and cash flow of our
subsidiaries and joint ventures and the distribution of that cash to us.
Distributions from our joint ventures are subject to the discretion of their
respective management committees. In addition, from time to time, our joint
ventures and some of our subsidiaries have separate credit arrangements that
contain various restrictive covenants. Among other things, those covenants limit
or restrict each such company's ability to make distributions to us under
certain circumstances. Further, each joint venture's charter documents typically
vest in its management committee sole discretion regarding distributions.
Accordingly, our joint ventures and our unrestricted subsidiaries may not
continue to make distributions to us at current levels or at all.

Moreover, pursuant to Deepwater Gateway's credit arrangements, we have
agreed to return a limited amount of the distributions made to us by Deepwater
Gateway if certain conditions exist.

WE CANNOT CAUSE OUR JOINT VENTURES TO TAKE OR NOT TO TAKE CERTAIN ACTIONS
UNLESS SOME OR ALL OF OUR JOINT VENTURE PARTICIPANTS AGREE.

Due to the nature of joint ventures, each participant (including us) in
each of our joint ventures, including Poseidon, Deepwater Gateway and Coyote Gas
Treating, LLC, has made substantial investments (including contributions and
other commitments) in that joint venture and, accordingly, has required that the
relevant charter documents contain certain features designed to provide each
participant with the opportunity to participate in the management of the joint
venture and to protect its investment in that joint venture, as well as any
other assets which may be substantially dependent on or otherwise affected by
the activities of that joint venture. These participation and protective
features include a corporate governance structure that requires at least a
majority in interest vote to authorize many basic activities and requires a
greater voting interest (sometimes up to 100 percent) to authorize more
significant activities. Examples of these more significant activities are large
expenditures or contractual commitments, the construction or acquisition of
assets, borrowing money or otherwise raising capital, transactions with
affiliates of a joint venture participant, litigation and transactions not in
the ordinary course of business, among others. Thus, without the concurrence of
joint venture participants with enough voting interests, we cannot cause any of
our joint ventures to take or not to take certain actions, even though those
actions may be in the best interest of the particular joint venture or us. As of
December 31, 2002, our aggregate investments in Deepwater Gateway, Coyote Gas
Treating, L.L.C. and Poseidon totaled $33 million, $0.7 million and $40 million.

WE DO NOT HAVE THE SAME FLEXIBILITY AS OTHER TYPES OF ORGANIZATIONS TO
ACCUMULATE CASH AND EQUITY TO PROTECT AGAINST ILLIQUIDITY IN THE FUTURE.

Unlike a corporation, our partnership agreement requires us to make
quarterly distributions to our unitholders of all available cash reduced by any
amounts reserved for commitments and contingencies, including capital and
operating costs and debt service requirements. The value of our units and other
limited partner interests will decrease in direct correlation with decreases in
the amount we distribute per unit. Accordingly, if we experience a liquidity
problem in the future, we may not be able to issue more equity to recapitalize.

75

CHANGES OF CONTROL OF OUR GENERAL PARTNER MAY ADVERSELY AFFECT YOU.

Our results of operations and, thus, our ability to pay amounts due under
the debt securities and to make cash distributions could be adversely affected
if there is a change of control of our general partner. For example, El Paso
Corporation and its subsidiaries are parties to various credit agreements and
other financing arrangements, the obligations of which may be collateralized
(directly or indirectly). El Paso Corporation and its subsidiaries have used,
and may use in the future, their interests, which include our general partner
interest, common units, Series C units and Series B preference units as
collateral. These arrangements may allow such lenders to foreclose on that
collateral in the event of a default. Further, El Paso Corporation could sell
our general partner or any of the common units or other limited partner
interests it holds. El Paso Corporation's sale of 50 percent or more of our
general partner would constitute a change of control under our existing credit
agreement and indentures. In such a circumstance, our indebtedness for borrowed
money would effectively become due and payable unless our creditors agreed
otherwise, and we might be required to refinance our indebtedness, potentially
on less advantageous terms. In addition, El Paso Corporation could sell control
of our general partner to another company with less familiarity and experience
with our businesses and with different business philosophies and objectives. In
such a situation, we may not be able to refinance our indebtedness. Any such
acquirer also may not continue our current business strategy, or even a business
strategy economically compatible with our current business strategy.

TAX RISKS

WE HAVE NOT RECEIVED A RULING OR ASSURANCES FROM THE IRS ON ANY MATTERS
AFFECTING US.

We have not requested, and do not intend to request, any ruling from the
Internal Revenue Service (IRS) with respect to our classification, or the
classification of any of our subsidiaries which are organized as limited
liability companies or partnerships, as a partnership for federal income tax
purposes. Accordingly, the IRS may propose positions that differ from the
conclusions expressed by us. It may be necessary to resort to administrative or
court proceedings in an effort to sustain some or all of those conclusions, and
some or all of those conclusions ultimately may not be sustained. The limited
partners and our general partner will bear, directly or indirectly, the costs of
any contest with the IRS.

OUR TAX TREATMENT DEPENDS ON OUR PARTNERSHIP STATUS AND IF THE IRS TREATS US
AS A CORPORATION FOR TAX PURPOSES, IT WOULD ADVERSELY AFFECT DISTRIBUTIONS TO
OUR UNITHOLDERS AND OUR ABILITY TO MAKE PAYMENTS ON OUR DEBT SECURITIES.

Based upon the continued accuracy of the representations of our general
partner, we believe that under current law and regulations we and our
subsidiaries which are limited liability companies or partnerships have been and
will continue to be classified as partnerships for federal income tax purposes
or will be ignored as separate entities for federal income tax purposes.
However, as stated above, we have not requested, and will not request, any
ruling from the IRS as to this status. In addition, you cannot be sure that
those representations will continue to be accurate. If the IRS were to challenge
our federal income tax status or the status of one of our subsidiaries, such a
challenge could result in (i) an audit of each unitholder's entire tax return
and (ii) adjustments to items on that return that are unrelated to the ownership
of units or other limited partner interests. In addition, each unitholder would
bear the cost of any expenses incurred in connection with an examination of its
personal tax return. Except as specifically noted, this discussion assumes that
we and our subsidiaries which are organized as limited liability companies or
partnerships have been and are treated as single member limited liability
companies disregarded from their owners or partnerships for federal income tax
purposes.

If we or any of our subsidiaries which are organized as limited liability
companies, limited partnerships or general partnerships were taxable as a
corporation for federal income tax purposes in any taxable year, its income,
gains, losses and deductions would be reflected on its tax return rather than
being passed through (proportionately) to unitholders, and its net income would
be taxed at corporate rates. This would materially and adversely affect our
ability to make payments on our debt securities. In addition, some or all of the

76

distributions made to unitholders would be treated as dividend income and would
be reduced as a result of the federal, state and local taxes paid by us or our
subsidiaries.

WE MAINTAIN UNIFORMITY OF OUR LIMITED PARTNER INTERESTS THROUGH NONCONFORMING
DEPRECIATION CONVENTIONS.

Since we cannot match transferors and transferees of our limited partner
interests, we must maintain uniformity of the economic and tax characteristics
of the limited partner interests to their purchasers. To maintain uniformity and
for other reasons, we have adopted certain depreciation conventions. The IRS may
challenge those conventions and, if such a challenge were sustained, the
uniformity or the value of our limited partner interests may be affected. For
example, non-uniformity could adversely affect the amount of tax depreciation
available to unitholders and could have a negative impact on the value of their
limited partner interests.

UNITHOLDERS CAN ONLY DEDUCT CERTAIN LOSSES.

Any losses that we generate will be available to offset future income
(except certain portfolio net income) that we generate and cannot be used to
offset income from any other source, including other passive activities or
investments unless the unitholder disposes of its entire interest.

UNITHOLDERS' PARTNERSHIP TAX INFORMATION MAY BE AUDITED.

We will furnish each unitholder a Schedule K-1 that sets forth its
allocable share of income, gains, losses and deductions. In preparing this
schedule, we will use various accounting and reporting conventions and various
depreciation and amortization methods we have adopted. We cannot guarantee that
this schedule will yield a result that conforms to statutory or regulatory
requirements or to administrative pronouncements of the IRS. Further, our tax
return may be audited, and any such audit could result in an audit of each
unitholder's individual tax return as well as increased liabilities for taxes
because of adjustments resulting from the audit.

UNITHOLDERS' TAX LIABILITY RESULTING FROM AN INVESTMENT IN OUR LIMITED PARTNER
INTERESTS COULD EXCEED ANY CASH UNITHOLDERS RECEIVE AS A DISTRIBUTION FROM US
OR THE PROCEEDS FROM DISPOSITIONS OF THOSE SECURITIES.

A unitholder will be required to pay federal income tax and, in certain
cases, state and local income taxes on its allocable share of our income,
whether or not it receives any cash distributions from us. A unitholder may not
receive cash distributions equal to its allocable share of taxable income from
us. In fact, a unitholder may incur tax liability in excess of the amount of
cash distribution we make to it or the cash it receives on the sale of its units
or other limited partner interests.

TAX-EXEMPT ORGANIZATIONS AND CERTAIN OTHER INVESTORS MAY EXPERIENCE ADVERSE
TAX CONSEQUENCES FROM OWNERSHIP OF OUR SECURITIES.

Investment in our securities by tax-exempt organizations and regulated
investment companies raises issues unique to such persons. Virtually all of our
income allocated to a tax-exempt organization will be unrelated business taxable
income and will be taxable to such tax-exempt organization. Additionally, very
little of our income will qualify for purposes of determining whether an
investor will qualify as a regulated investment company. Furthermore, an
investor who is a nonresident alien, a foreign corporation or other foreign
person will be required to file federal income tax returns and to pay taxes on
his share of our taxable income because he will be regarded as being engaged in
a trade or business in the United States as a result of his ownership of units
or other limited partnership units. We have the right to redeem units or other
limited partner interests held by certain non-U.S. residents or holders
otherwise not qualified to become one of our limited partners.

77

WE ARE REGISTERED AS A TAX SHELTER. ANY IRS AUDIT WHICH ADJUSTS OUR RETURNS
WOULD ALSO ADJUST EACH UNITHOLDER'S RETURNS.

We have been registered with the IRS as a "tax shelter." The tax shelter
registration number is 93084000079. As a result, we may be audited by the IRS
and tax adjustments may be made. The right of a unitholder owning less than a
one percent profit interest in us to participate in the income tax audit process
is limited. Further, any adjustments in our tax returns will lead to adjustments
in each unitholder's returns and may lead to audits of each unitholder's returns
and adjustments of items unrelated to us. Each unitholder would bear the cost of
any expenses incurred in connection with an examination of its personal tax
return.

UNITHOLDERS MAY HAVE NEGATIVE TAX CONSEQUENCES IF WE DEFAULT ON OUR DEBT OR
SELL ASSETS.

If we default on any of our debt, the lenders will have the right to sue us
for non-payment. Such an action could cause an investment loss and cause
negative tax consequences for each unitholder through the realization of taxable
income by it without a corresponding cash distribution. Likewise, if we were to
dispose of assets and realize a taxable gain while there is substantial debt
outstanding and proceeds of the sale were applied to the debt, each unitholder
could have increased taxable income without a corresponding cash distribution.

WE WILL TREAT EACH PURCHASER OF UNITS AS HAVING THE SAME TAX BENEFITS WITHOUT
REGARD TO THE UNITS PURCHASED. THE IRS MAY CHALLENGE THIS TREATMENT, WHICH
COULD ADVERSELY AFFECT THE VALUE OF THE UNITS.

Because we cannot match transferors and transferees of common units, we
have adopted depreciation and amortization positions that could be challenged. A
successful IRS challenge to those positions could adversely affect the amount of
tax benefits available to you. It also could affect the timing of these tax
benefits or the amount of gain from your sale of common units and could have a
negative impact on the value of the common units or result in audit adjustments
to your tax returns.

YOU WILL LIKELY BE SUBJECT TO STATE AND LOCAL TAXES IN STATES WHERE YOU DO NOT
LIVE AS A RESULT OF AN INVESTMENT IN OUR UNITS.

In addition to federal income taxes, you will likely be subject to other
taxes, including state and local taxes, unincorporated business taxes and
estate, inheritance or intangible taxes that are imposed by the various
jurisdictions in which we do business or own property and in which you do not
reside. You may be required to file state and local income tax returns and pay
state and local income taxes in many or all of the jurisdictions in which we do
business. Further, you may be subject to penalties for failure to comply with
those requirements. We own assets and do business in six states. Four of these
states currently impose a personal income tax on partners of partnerships doing
business in those states but who are not residents of those states. It is your
responsibility to file all United States federal, state and local tax returns.
Our counsel has not rendered an opinion on the state or local tax consequences
of an investment in the common units.

78

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We may utilize derivative financial instruments to manage our exposure to
movements in interest rates and commodity prices. In accordance with procedures
established by our general partner, we monitor current economic conditions and
evaluate our expectations of future prices and interest rates when making
decisions with respect to risk management. We generally do not enter into
derivative transactions for trading purposes and had no trading activities
during 2002 and 2001.

NON-TRADING COMMODITY PRICE RISK

A majority of our commodity sales and purchases are at spot market or
forward market prices. We use futures, forward contracts, and swaps to limit our
exposure to fluctuations in the commodity markets and allow for a fixed cash
flow stream from these activities.

Our customers and producers regularly negotiate contracts with us to
provide natural gas gathering, treating and processing services for specific
volumes of natural gas and NGL under which we receive variable rate fees that
are based on an index plus a margin. In an effort to minimize fluctuations in
our cash flow that may result from fluctuations in natural gas and NGL prices,
we manage this price risk by simultaneously entering fixed-for-floating
commodity price swaps for comparable volumes of natural gas and NGL that settle
over the same time periods as the underlying contracts. These commodity price
swap transactions are commonly referred to as "hedges," because if effective,
they stabilize the amounts we receive for providing natural gas and NGL
gathering, treating and processing services that would otherwise fluctuate with
changes in natural gas and NGL prices. We settle the commodity price swap
transactions by paying the negative difference or receiving the positive
difference between the fixed price specified in the contract and the applicable
settlement price indicated for the applicable index as published in the
periodical "Inside FERC" for natural gas contracts and the price indicated by
the Oil Pricing Information Service (OPIS) for NGL contracts for the specified
commodity on the established settlement date. No ineffectiveness exists in our
hedging relationships because all purchases and sales prices are based on the
same index and volumes as the hedge transaction.

Our hedging activities also expose us to credit risk arising from the
counterparty to the hedging transaction. We generally manage the credit risk by
entering into derivative contracts with established organizations that have
investment grade credit ratings from established credit ratings agencies (e.g.,
Standard & Poor's or Moody's Investors Services). We do not require collateral
and do not anticipate non-performance by counterparties to our derivative
transactions.

In August 2002 in anticipation of our acquisition of the San Juan assets,
we entered into derivative financial instruments to receive fixed prices for
specified volumes of natural gas for the 2003 calendar year. The derivative is a
fixed-for-floating commodity price swap on 30,000 MMBtu/d of natural gas at a
weighted average receive price of $3.525 per Dth for delivery through December
2003. Since the derivative was not associated with our then current operating
activities, it did not qualify for hedge accounting under SFAS No. 133. As a
result, we accounted for this commodity price swap based upon mark-to-market
accounting until we acquired the San Juan assets on November 27, 2002. With the
acquisition of the San Juan assets, we designated the previously acquired
fixed-for-floating commodity price swaps as a cash flow hedge. We recognized a
gain of $0.4 million in income for the change in value from the date we entered
the derivative until the San Juan acquisition date.

In connection with our EPN Holding acquisition in April 2002, we obtained a
42.3 percent interest in the Indian Basin natural gas processing plant. Our
Indian Basin plant provides NGL processing services for customers and receives a
portion of the NGL processed as payment for these services, which we then sell
at prevailing market prices. Due to fluctuations in the market price for NGL, we
entered into fixed-for-floating commodity price swaps during 2002 whereby we
receive a fixed price based on the daily average price for the specified
contract month based upon the OPIS posting prices for the particular month for
established volumes that settle over the same time periods we expect to receive
NGL from our processing activities. All of the fixed-for-floating commodity
price swaps associated with our Indian Basin plant were settled as of December
31, 2002.
79

During 2002, our EPIA operation entered into sales contracts with specific
customers for the sale of predetermined volumes of natural gas for delivery over
established periods of time at a fixed price based on the SONAT-Louisiana index
(Southern Natural Pipeline index as published by the periodical "Inside FERC")
plus a margin. We simultaneously entered into fixed-for-floating commodity price
swaps for comparable volumes of natural gas at fixed prices indicated in the
SONAT-Louisiana index that settle over the same time periods as the underlying
sales contracts. The effect of these transactions is to fix the margins and
substantially eliminate the price risk associated with our sales contracts.

No ineffectiveness exists in our hedging relationships because all purchase
and sale prices are based on the same index and volumes as the hedge
transactions. The following tables present information about our non-trading
commodity price swaps at December 31:

- ----------

(a) Fair value is determined from prices indicated in the SONAT-Louisiana index
as developed from market data accumulated from a data base we maintain of
executed commodity transactions.

- ----------

(b) Fair value is determined from prices indicated in the San Juan index as
developed from market data accumulated from a data base we maintain of
executed commodity transactions.

As reflected in the tables above, at December 31, 2002 we have an
unrealized loss associated with our natural gas fixed-for-floating commodity
price swaps of approximately $4.7 million. Our exposure to market risk
associated with commodity prices increased in 2002 as a result of our
acquisitions of the Indian Basin plant and the San Juan assets due to the
additional volumes of NGL and natural gas we buy and sell at market prices.

INTEREST RATE RISK

We utilize both fixed and variable rate long-term debt, and are exposed to
market risk resulting from the variable interest rates under our credit
facility, EPN Holding term credit facility and senior secured acquisition term
loan. We are exposed to similar risk under the various joint venture credit
facilities and loan agreements. Since we have $858 million outstanding under our
indentures at fixed interest rates ranging from 8 1/2% to 10 5/8% at December
31, 2002, we have not benefited from the recent declines in interest rates. On
the other hand, had interest rates increased, we would not have incurred
additional interest costs.

The table below depicts principal cash flows and related weighted average
interest rates of our debt obligations, by expected maturity dates at December
31, 2002. The carrying amounts of our revolving credit facility, EPN Holding
term credit facility, the senior secured term loans and the limited recourse
loan at December 31, 2002 and 2001, approximate the fair value of these
instruments because the variable interest

80

rates on these loans reprice frequently to reflect currently available interest
rates. The fair value of the senior subordinated notes has been determined based
on quoted market prices for the same or similar issues.

At December 31, 2002, we had variable rate debt outstanding with an
aggregate principal balance of $1,048.5 million and a weighted average interest
rate of 5.1%. The following table illustrates the amount of the increase in net
income from a decrease in interest rates or the amount of the decrease in income
from an increase in interest rates under four possible scenarios based upon the
aggregate balance of variable rate debt outstanding at December 31, 2002
(dollars in millions):

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

* one basis point is equal to one one-hundredth of one percent.

Poseidon Oil Pipeline Company, L.L.C., one of our unconsolidated
affiliates, has a revolving credit facility with $185 million of total borrowing
capacity and $148 million outstanding at December 31, 2002. In January 2002,
Poseidon entered into a two-year interest rate swap agreement to fix the
variable LIBOR based interest rate on $75 million of the amounts outstanding on
their variable rate revolving credit facility at 3.49% through January 2004.
Poseidon, under its credit facility, currently pays an additional 1.50% over the
LIBOR rate resulting in an effective interest rate of 4.99% on the hedged
notional amount.

81

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)

See accompanying notes.
82

EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME -- (CONTINUED)
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)

See accompanying notes.
83

EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)

See accompanying notes.
84

EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

See accompanying notes.
85

EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(IN THOUSANDS)

- ---------------
(1) We issued 10,937,500 of our Series C units to El Paso Corporation for a
value of $350 million in connection with our acquisition of the San Juan
assets. A discussion of this new class of units is included in Note 8.
(2) El Paso Energy Partners Company, a wholly owned subsidiary of El Paso
Corporation, owns a one percent general partner interest in us.
(3) Income allocation to our general partner includes both its incentive
distributions and its one percent ownership interest.

See accompanying notes.
86

EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
AND CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
(IN THOUSANDS)

COMPREHENSIVE INCOME

ACCUMULATED OTHER COMPREHENSIVE INCOME

See accompanying notes.
87

EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization

We are a publicly held Delaware master limited partnership established in
1993 for the purpose of providing midstream energy services, including
gathering, transportation, fractionation, storage and other related activities
for producers of natural gas and oil, onshore and offshore in the Gulf of
Mexico. As of December 31, 2002, we had 44,030,314 common units outstanding
representing limited partner interests, 125,392 Series B preference units
outstanding representing preference interests and 10,937,500 Series C units
outstanding representing non-voting limited partner interests. On that date, the
public owned 32,356,069 common units, or 73.5 percent of our outstanding common
units, and El Paso Corporation, through its subsidiaries, owned 11,674,245
common units, or 26.5 percent of our outstanding common units, all of our Series
B preference units, all of our Series C units and our one percent general
partner interest.

Basis of Presentation and Principles of Consolidation

Our consolidated financial statements include the accounts of all
majority-owned, controlled subsidiaries after the elimination of all significant
intercompany accounts and transactions. We account for investments in companies
where we have the ability to exert significant influence over, but not control
over operating and financial policies, using the equity method of accounting.
Prior to May 2001, our general partner's approximate one percent non-managing
interest in twelve of our subsidiaries represented the minority interest in our
consolidated financial statements. In May 2001, we purchased our general
partner's one percent non-managing ownership interests. During 2002, third
parties have minority ownership interests in Matagorda Island Area Gathering
System and Arizona Gas, L.L.C. The assets, liabilities and operations of these
entities are included in our financial statements and we account for the third
party ownership interest as minority interest in our balance sheet and as
minority interest in consolidated subsidiaries in our statement of income. Our
consolidated financial statements for prior periods include reclassifications
that were made to conform to the current year presentation. Those
reclassifications have no impact on reported net income or partners' capital. We
have reflected the results of operations from our Prince assets disposition as
discontinued operations for all periods presented. See Note 2 for a further
discussion of our Prince assets disposition.

Use of Estimates

The preparation of our financial statements in conformity with accounting
principles generally accepted in the United States requires us to make estimates
and assumptions that affect the reported amounts of assets, liabilities,
revenues and expenses and disclosure of contingent assets and liabilities that
exist at the date of our financial statements. While we believe our estimates
are appropriate, actual results can, and often do, differ from those estimates.

Accounting for Regulated Operations

Our HIOS interstate natural gas system and our Petal storage facility are
subject to the jurisdiction of FERC in accordance with the Natural Gas Act of
1938 and the Natural Gas Policy Act of 1978. Each system operates under separate
FERC approved tariffs that establish rates, terms and conditions under which
each system provides services to its customers. Our businesses that are subject
to the regulations and accounting requirements of FERC have followed the
accounting requirements of Statement of Financial Accounting Standards (SFAS)
No. 71, Accounting for the Effects of Certain Types of Regulation, which may
differ from the accounting requirements of our non-regulated entities.
Transactions that have been recorded differently as a result of regulatory
accounting requirements include the capitalization of an equity return component
on regulated capital projects, and other costs and taxes included in, or
expected to be included in, future rates.

88

EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

When the accounting method followed is required by or allowed by the
regulatory authority for rate-making purposes, the method conforms to the
generally accepted accounting principle (GAAP) of matching costs with the
revenues to which they apply.

Cash and Cash Equivalents

We consider short-term investments with little risk of change in value
because of changes in interest rates and purchased with an original maturity of
less than three months to be cash equivalents.

Allowance for Doubtful Accounts

We have established an allowance for losses on accounts which may become
uncollectible. Collectibility is reviewed regularly and the allowance is
adjusted as necessary, primarily under the specific identification method. At
December 31, 2002 and 2001, the allowance was $2.5 million and $1.8 million.

Natural Gas Imbalances

Natural gas imbalances result from differences in gas volumes received from
and delivered to our customers and arise when a customer delivers more or less
gas into our pipelines than they take out. These imbalances are settled in kind
through a tracking mechanism, negotiated cash-outs between parties, or are
subject to a cash-out procedure and are valued at prices representing the
estimated value of these imbalances upon settlement. Changes in natural gas
prices may impact our valuation. We do not value our imbalances based on current
month prices because it is not likely that we would purchase or receive natural
gas at that point in time to settle the imbalance. Natural gas imbalances are
reflected in accounts receivable or accounts payable, as appropriate, in our
accompanying consolidated balance sheets. Our imbalances at December 31, 2002,
arose as a result of our acquisitions during 2002. We did not have significant
imbalances at December 31, 2001. Our imbalance receivables and imbalance
payables were as follows at December 31, 2002 (in thousands):

Imbalance Receivables
Trade..................................................... $ 88,929
Affiliates................................................ $ 15,460

Imbalance Payables
Trade..................................................... $104,035
Affiliates................................................ $ 22,316

Property, Plant and Equipment

We record our property, plant and equipment at its original cost of
construction or, upon acquisition, the fair value of the asset acquired.
Additionally, we capitalize direct costs, such as labor and materials, and
indirect costs, such as overhead, interest and in our regulated businesses that
apply the provisions of SFAS No. 71, an equity return component. We also
capitalize the major units of property replacements or improvements and expense
minor items including repair and maintenance costs.

For our regulated interstate system and storage facility we use the
composite (group) method to depreciate regulated property, plant and equipment.
Under this method, assets with similar lives and other characteristics are
grouped and depreciated as one asset. We apply the depreciation rate approved in
our tariff, to the total cost of the group, until its net book value equals its
estimated salvage value.

89

EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Our non-regulated gathering pipelines, platforms and related facilities,
processing facilities and equipment, and storage facilities and equipment are
depreciated on a straight-line basis over the estimated useful lives which are
as follows:

We account for our oil and natural gas exploration and production
activities using the successful efforts method of accounting. Under this method,
costs of successful exploratory wells, developmental wells and acquisitions of
mineral leasehold interests are capitalized. Production, exploratory dry hole
and other exploration costs, including geological and geophysical costs and
delay rentals, are expensed as incurred. Unproved properties are assessed
periodically and any impairment in value is recognized currently as
depreciation, depletion and amortization expense.

Depreciation, depletion and amortization of the capitalized costs of
producing oil and natural gas properties, consisting principally of tangible and
intangible costs incurred in developing a property and costs of productive
leasehold interests, are computed on the unit-of-production method.
Unit-of-production rates are based on annual estimates of remaining proved
developed reserves or proved reserves, as appropriate, for each property.

Estimated dismantlement, restoration and abandonment costs and estimated
residual salvage values are taken into account in determining depreciation
provisions for gathering pipelines, platforms, related facilities and oil and
natural gas properties. At December 31, 2002 and 2001, accrued abandonment costs
were $24.6 million and $23.5 million. As discussed below, upon our adoption of
SFAS No. 143 Accounting for Asset Retirement Obligations the amounts accrued and
capitalized will be adjusted to conform to the provisions of that statement.

Retirements, sales and disposals of assets are recorded by eliminating the
related costs and accumulated depreciation, depletion and amortization of the
disposed assets with any resulting gain or loss reflected in income.

Goodwill and Other Intangible Assets

We adopted the provisions of SFAS No. 142 Goodwill and Other Intangible
Assets on January 1, 2002, except for goodwill and intangible assets we acquired
after June 30, 2001 for which we adopted the provisions immediately.
Accordingly, we record identifiable intangible assets we acquire individually or
with a group of other assets at fair value upon acquisition. Identifiable
intangible assets with finite useful lives are amortized to expense over the
estimated useful life of the asset. Identifiable intangible assets with
indefinite useful lives and goodwill are evaluated annually for impairment by
comparison of their carrying amounts with the fair value of the individual
assets. We recognize an impairment loss in income for the amount by which the
carrying value of any identifiable intangible asset or goodwill exceeds the fair
value of the specific assets. As of December 31, 2002 and 2001, we had no
goodwill, other than described below.

As of December 31, 2002 and 2001, the carrying amount of our equity
investment in Poseidon exceeded the underlying equity in net assets by
approximately $3.0 million. With our adoption of SFAS No. 142 on January 1,
2002, we no longer amortize this excess amount and will test for impairment if
an event occurs that indicates there may be a loss in value. Prior to January 1,
2002, we amortized this excess amount using the straight line method over
approximately 30 years. This excess amount is reflected on our accompanying
consolidated balance sheets in investments in unconsolidated affiliates. Our
adoption of this statement did not have a material impact on our financial
position or results of operations.

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As part of our acquisition of the EPN Holding assets and the San Juan
assets, we obtained intangible assets representing contractual rights under
dedication and transportation agreements with producers. As of December 31,
2002, the value of these intangible assets was approximately $4.0 million and is
reflected on our accompanying consolidated balance sheet as intangible assets.
We amortize these intangible assets to expense using the units-of-production
method over the expected lives of the reserves ranging from 20 to 45 years.

Impairment and Disposal of Long-Lived Assets

We adopted the provisions of SFAS No. 144 Accounting for the Impairment or
Disposal of Long-Lived Assets on January 1, 2002. Accordingly, we evaluate the
recoverability of selected long-lived assets when adverse events or changes in
circumstances indicate that the carrying value of an asset or group of assets
may not be recoverable. We determine the recoverability of an asset or group of
assets by estimating the undiscounted cash flows expected to result from the use
and eventual disposition of the asset or group of assets at the lowest level for
which separate cash flows can be measured. If the total of the undiscounted cash
flows is less that the carrying amount for the assets, we estimate the fair
value of the asset or group of assets and recognize the amount by which the
carrying value exceeds the fair value as an impairment loss in income from
operations in the period the impairment is determined.

Additionally, as required by SFAS No. 144, we classify long-lived assets to
be disposed of other than by sale (e.g., abandonment, exchange or distribution)
as held and used until the item is abandoned, exchanged or distributed. We
evaluate assets to be disposed of other than by sale for impairment and
recognize a loss for the excess of the carrying value over the fair value.
Long-lived assets to be disposed of through sale recognition meeting specific
criteria are classified as "Held for Sale" and measured at the lower of their
cost or fair value less cost to sell. We report the results of operations of a
component classified as held for sale, including any gain or loss recognized in
discontinued operations in the period(s) in which they occur and all prior
periods presented.

Capitalization of Interest

Interest and other financing costs are capitalized in connection with
construction and drilling activities as part of the cost of the asset and
amortized over the related asset's estimated useful life.

Debt Issue Costs

Debt issue costs are capitalized and amortized over the life of the related
indebtedness using the effective interest method. Any unamortized debt issue
costs are expensed at the time the related indebtedness is repaid or terminated.
At December 31, 2002 and 2001, the unamortized amount of our debt issue costs
included in other noncurrent assets was $32.6 million and $17.0 million.

Revenue Recognition and Cost of Natural Gas, Oil and Other Products

Revenue from gathering and transportation of hydrocarbons is recognized
upon receipt of the hydrocarbons into the pipeline systems. Revenue from
commodity sales is recognized upon delivery. Commodity storage revenues and
platform access revenues consist primarily of fixed fees for capacity
reservation and some of the transportation contracts on our Viosca Knoll system
and our Indian Basin lateral also contain a fixed fee to reserve transportation
capacity. These fixed fees are recognized during the month in which the capacity
is reserved by the customer, regardless of how much capacity is actually used.
Revenue from processing services, treating services and fractionation services
is recognized in the period the services are provided. Interruptible revenues
from natural gas storage, which are generated by providing excess storage
capacity, are variable in nature and are recognized when the service is
provided. Other revenues generally are recorded when services have been provided
or products have been delivered.

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Prior to 2002, our cost of natural gas consisted primarily of natural gas
purchased at EPIA for resale. As a result of our acquisition of the EPN Holding
assets and the San Juan assets, we are now incurring additional costs related to
system imbalances and for the purchase of natural gas as part of our producer
services activities. As a convenience for our producers, we may purchase natural
gas from them at the wellhead at an index price less an amount that compensates
us for our gathering services. We then sell this gas into the open market at
points on our system at the same index price. We reflect these sales in our
revenues and the related purchases as cost of natural gas on the accompanying
consolidated statements of income.

Typhoon Oil Pipeline's transportation agreement with BHP and Chevron Texaco
provides that Typhoon Oil purchase the oil produced at the inlet of its pipeline
for an index price less an amount that compensates Typhoon Oil for
transportation services. At the outlet of its pipeline, Typhoon Oil resells this
oil back to these producers at the same index price. We reflect these sales in
our revenues and the related purchases as cost of oil.

Environmental Costs

We expense or capitalize expenditures for ongoing compliance with
environmental regulations that relate to past or current operations as
appropriate. We expense amounts for clean up of existing environmental
contamination caused by past operations which do not benefit future periods. We
record liabilities when our environmental assessments indicate that remediation
efforts are probable, and the costs can be reasonably estimated. Estimates of
our liabilities are based on currently available facts, existing technology and
presently enacted laws and regulations taking into consideration the likely
effects of inflation and other societal and economic factors, and include
estimates of associated legal costs. These amounts also consider prior
experience in remediating contaminated sites, other companies' clean-up
experience and data released by the Environmental Protection Agency (EPA) or
other organizations. These estimates are subject to revision in future periods
based on actual costs or new circumstances and are included in our balance sheet
in other noncurrent liabilities at their undiscounted amounts.

Accounting for Price Risk Management Activities

Our business activities expose us to a variety of risks, including
commodity price risk and interest rate risk. From time to time we engage in
price risk management activities for non-trading purposes to manage market risks
associated with commodities we purchase and sell and interest rates on variable
rate debt. Our price risk management activities involve the use of a variety of
derivative financial instruments, including:

- exchange-traded future contracts that involve cash settlement;

- forward contracts that involve cash settlements or physical delivery of a
commodity; and

- swap contracts that require payments to (or receipts from) counterparties
based on the difference between a fixed and a variable price, or two
variable prices, for a commodity or variable rate debt instrument.

Beginning in 2001, we account for all our derivative instruments in our
financial statements under SFAS No. 133, Accounting for Derivatives and Hedging
Activities. We record all derivatives in our balance sheet at their fair value
as other assets or other liabilities and classify them as current or noncurrent
based upon their anticipated settlement date.

For those instruments entered into to hedge risk and which qualify as
hedges, we apply the provisions of SFAS No. 133, and the accounting treatment
depends on each instrument's intended use and how it is designated. In addition
to its designation, a hedge must be effective. To be effective, changes in the
value of the derivative or its resulting cash flows must substantially offset
changes in the value or cash flows of the item being hedged.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

During 2000, prior to our adoption of SFAS No. 133, we entered into
commodity price swap instruments for non-trading purposes to manage our exposure
to price fluctuations on anticipated natural gas and crude oil sales
transactions.

We formally document all relationships between hedging instruments and
hedged items, as well as our risk management objectives and strategies for
undertaking various hedge transactions. All hedging instruments are linked to
the hedged asset, liability, firm commitment or forecasted transaction. We also
assess, both at the inception of the hedge and on an on-going basis, whether the
derivatives that are used in our hedging transactions are highly effective in
offsetting changes in cash flows or fair values of the hedged items. We
discontinue hedge accounting prospectively if we determine that a derivative is
not highly effective as a hedge or if we decide to discontinue the hedging
relationship.

During 2002 and 2001, we entered into cash flow hedges that qualify for
SFAS No. 133 treatment. Changes in the fair value of a derivative designated as
a cash flow hedge are recorded in accumulated other comprehensive income for the
portion of the change in value of the derivative that is effective. The
ineffective portion of the derivative is recorded in earnings in the current
period. Classification in the income statement of the ineffective portion is
based on the income classification of the item being hedged. We reclassify the
gains or losses resulting from the sale, maturity, extinguishment or termination
of derivative instruments designated as hedges from accumulated other
comprehensive income to operating income in our consolidated statements of
income. We classify cash inflows and outflows associated with the settlement of
our derivative transactions as cash flows from operating activities in our
consolidated statements of cash flows.

We also record our ownership percentage of the changes in the fair value of
derivatives of our investments in unconsolidated affiliates in accumulated other
comprehensive income.

We may also purchase and sell instruments to economically hedge price
fluctuations in the commodity markets. These instruments are not documented as
hedges due to their short-term nature, or do not qualify under the provisions of
SFAS No. 133 for hedge accounting due to the terms in the instruments. Where
such derivatives do not qualify, changes in their fair value are recorded in
earnings in the current period.

In August 2002, we entered into a derivative financial instrument to hedge
our exposure during 2003 to changes in natural gas prices in the San Juan Basin
in anticipation of our acquisition of the San Juan assets. From August 2002
through our acquisition date, November 27, 2002, we accounted for this
derivative under mark-to-market accounting since it did not qualify for hedge
accounting under SFAS No. 133. Beginning with the acquisition date in November
2002, we have designated this derivative as a cash flow hedge and are accounting
for it as such under SFAS No. 133.

To qualify for hedge accounting, prior to our adoption of SFAS No. 133, the
transactions must have reduced the price risk of the underlying hedged items, be
designated as hedges at inception, and resulted in cash flows and financial
impacts which were inversely correlated to the position being hedged. If
correlation ceased to exist, hedge accounting was terminated and mark-to-market
accounting was applied. Gains and losses resulting from hedging activities and
the termination of any hedging instruments were initially deferred and included
as an increase or decrease to oil and natural gas sales in the period in which
the hedged production was sold.

During the normal course of our business, we may enter into contracts that
qualify as derivatives under the provisions of SFAS No. 133. As a result, we
evaluate our contracts to determine whether derivative accounting is
appropriate. Contracts that meet the criteria of a derivative and qualify as
"normal purchases" and "normal sales", as those terms are defined in SFAS No.
133, may be excluded from SFAS No. 133 treatment.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Income Taxes

As of December 31, 2002, neither we nor any of our subsidiaries are taxable
entities. Tarpon Transmission Company, our only taxable entity in 2000, was sold
in January 2001, and as a result, we incurred no income tax liability in 2001
and 2002. However, the taxable income or loss resulting from our operations will
ultimately be included in the federal and state income tax returns of the
general and limited partners. Individual partners will have different investment
bases depending upon the timing and price of their acquisition of partnership
units. Further, each partner's tax accounting, which is partially dependent upon
his tax position, may differ from the accounting followed in the consolidated
financial statements. Accordingly, there could be significant differences
between each individual partner's tax basis and his share of the net assets
reported in the consolidated financial statements. We do not have access to
information about each individual partner's tax attributes and the aggregate tax
bases cannot be readily determined.

We utilized SFAS No. 109, Accounting for Income Taxes, to account for
Tarpon's income taxes subject to federal corporate income taxation. The income
tax benefit reported in our consolidated statement of income for the year ended
2000 relates solely to Tarpon's book loss at the effective statutory income tax
rate for the respective period since no material differences existed between
book and taxable income. In January 2001, we sold our interest in Tarpon as a
result of a FTC order. All of Tarpon's deferred tax liabilities were assumed by
the buyer at the time of sale.

Income (Loss) per Common Unit

Basic income (loss) per common unit excludes dilution and is computed by
dividing net income (loss) attributable to the common unitholders by the
weighted average number of common units outstanding during the period. Diluted
income (loss) per common unit reflects potential dilution and is computed by
dividing net income (loss) attributable to the common unitholders by the
weighted average number of common units outstanding during the period increased
by the number of additional common units that would have been outstanding if the
potentially dilutive units had been issued.

Basic income (loss) per common unit and diluted income (loss) per common
unit are the same for the years ended December 31, 2002, 2001, and 2000, as the
number of potentially dilutive units were so small as not to cause the diluted
earnings per unit to be different from the basic earnings per unit. We include
the outstanding publicly held preference units in 2000 in the basic and diluted
net income (loss) per common unit calculation as if the publicly held preference
units had been converted into common units. As of October 2000, all publicly
held preference units have been converted into common units or redeemed.

Comprehensive Income

Our comprehensive income is determined based on net income (loss), adjusted
for changes in accumulated other comprehensive income (loss) from our cash flow
hedging activities associated with our EPIA operations, our Indian Basin
processing plant, the San Juan assets and our unconsolidated affiliate, Poseidon
Oil Pipeline Company, L.L.C.

Unit-Based Compensation

We apply the provisions of Accounting Principles Board Opinion (APB) No. 25
and related interpretations in accounting for unit options issued to former
employees of our general partner and our board of directors. Accordingly,
compensation expense is not recognized for these unit options unless the options
were granted at an exercise price lower than the market price of common units on
the grant date. We use fixed plan accounting for our restricted unit grants. We
apply the provisions of SFAS No. 123, Accounting for Stock-Based Compensation,
for unit options issued to employees of affiliates of our general partner. For
these options, we amortize the fair value of these options as of the grant date
over the vesting period of the grant.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In December 2002, the Financial Accounting Standards Board (FASB) issued
SFAS No. 148, Accounting for Stock-Based Compensation Transition and Disclosure.
This statement amends SFAS No. 123, to provide alternative methods of transition
for a voluntary change to the fair value method of accounting for stock-based
employee compensation. In addition, this statement amends the disclosure
requirements of SFAS No. 123 to require prominent disclosures in both annual and
interim financial statements about the methods of accounting for stock-based
employee compensation and the effect of the method used on reported results.
This statement is effective for the fiscal years ending after December 15, 2002.
We have decided that we will continue to use APB No. 25 to value our stock-based
compensation and will include data providing the pro forma income impacts of
using the fair value method as required by SFAS No. 148.

The following discloses our stock-based compensation impact on net income
as required by SFAS No. 148. If compensation expense for the stock-based
compensation plans under our Omnibus Plan and Director Plan, as described in
Note 8, accounted for under APB 25, had been determined applying the provisions
of SFAS No. 123, and using the Black-Scholes weighted average fair value of
options granted as described in Note 8, our net income (loss) allocated to the
common unitholders and net income (loss) per common unit for 2002, 2001, and
2000 would approximate the pro forma amounts below:

The effects of applying SFAS No. 123 in this pro forma disclosure are not
indicative of future amounts.

Business Combinations

In July 2001, the FASB issued SFAS No. 141, Business Combinations. This
statement requires that all transactions that fit the definition of a business
combination be accounted for using the purchase method and prohibits the use of
the pooling of interests method for all business combinations initiated after
June 30, 2001. This statement also established specific criteria for the
recognition of intangible assets separately from goodwill and requires
unallocated negative goodwill to be written off immediately as an extraordinary
item. The accounting for any business combination we undertake in the future
will be impacted by this standard. We adopted the provisions of this standard
and applied them to each of our acquisitions initiated after June 30, 2001. For
transactions initiated prior to June 30, 2001, we applied the provisions of APB
Opinion No. 16. Our adoption of SFAS No. 141 did not have a material effect on
our financial position or results of operations.

New Accounting Pronouncements Issued But Not Yet Adopted

Accounting for Asset Retirement Obligations. In June 2001, the FASB issued
SFAS No. 143, Accounting for Asset Retirement Obligations. This statement
requires companies to record a liability for the estimated retirement and
removal of assets used in their business. The liability is recorded at its fair
value, with a corresponding asset which is depreciated over the remaining useful
life of the long-lived asset to which the liability relates.

An ongoing expense will also be recognized for changes in the value of the
liability as a result of the passage of time. The provisions of SFAS No. 143 are
effective for fiscal years beginning after June 15, 2002

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and relates primarily to our obligations to plug abandoned wells. We expect that
we will record a cumulative effect of accounting change of approximately $1.7
million, as an increase to income upon our adoption of SFAS No. 143 on January
1, 2003. We also expect to record non-current retirement assets of approximately
$7.0 million with useful lives ranging from 11 to 19 years and non-current
retirement liabilities of approximately $5.3 million on January 1, 2003.

Other than our obligations to plug and abandon wells, we expect we cannot
estimate the costs to retire or remove assets used in our business because we
believe the assets do not have definite lives or we do not have the legal
obligation to abandon or dismantle the assets. Also, we believe that the life or
underlying reserves cannot be estimated. Therefore, we will not record any
liabilities relating to our assets, other than the liability associated with the
plug and abandonment of wells.

Reporting Gains and Losses from the Early Extinguishment of Debt. In April
2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and
64, Amendment of FASB Statement No. 13, and Technical Corrections. This
statement addresses how to report gains or losses resulting from the early
extinguishment of debt. Previously, any gains or losses were reported as an
extraordinary item. Upon adoption of SFAS No. 145, an entity will be required to
evaluate whether the debt extinguishment is extraordinary in nature, or whether
they should be included in income from continuing operations. This statement is
effective for our 2003 year-end reporting.

Accounting for Costs Associated with Exit or Disposal Activities. In July
2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or
Disposal Activities. This statement will require us to recognize costs
associated with exit or disposal activities when they are incurred rather than
when we commit to an exit or disposal plan. Examples of costs covered by this
guidance include lease termination costs, employee severance costs, associated
with a restructuring, discontinued operation, plant closing, or other exit or
disposal activities. This statement is effective for fiscal years beginning
after December 31, 2002 and will impact any exit or disposal activities that we
initiate after January 1, 2003.

Accounting for Guarantees. In November 2002, the FASB issued FASB
Interpretation (FIN) No. 45, Guarantor's Accounting and Disclosure Requirements
for Guarantees, Including Indirect Guarantees of Indebtedness of Others. This
interpretation requires that companies record a liability for all guarantees
issued after December 31, 2002, including financial, performance, and fair value
guarantees. This liability is recorded at its fair value upon issuance, and does
not affect any existing guarantees issued before January 31, 2003. This standard
also requires expanded disclosures on all existing guarantees at December 31,
2002. We have included the required disclosures in Note 10.

Consolidation of Variable Interest Entities. In January 2003, the FASB
issued FIN No. 46, Consolidation of Variable Interest Entities. This
interpretation defines a variable interest entity as a legal entity whose equity
owners do not have sufficient equity at risk and/or a controlling financial
interest in the entity. This standard requires that companies consolidate a
variable interest entity if it is allocated a majority of the entity's losses
and/or returns, including fees paid by the entity. The provisions of FIN No. 46
are effective for all variable interest entities created after January 31, 2003,
and are effective on July 1, 2003 for all variable interest entities created
before January 31, 2003. We do not believe this statement will have any effect
on us.

2. ACQUISITIONS AND DISPOSITIONS

San Juan Assets

In November 2002, we acquired from subsidiaries of El Paso Corporation,
interests in assets we collectively refer to as the San Juan assets which
consist of the following:

- 100 percent of El Paso Field Services' San Juan Gathering and Processing
Businesses, which include a natural gas gathering system and related
compression facilities, the Rattlesnake Treating Plant, a
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

50-percent equity interest in Coyote Gas Treating, L.L.C. which owns the
Coyote natural gas treating facility and the remaining interests in the
Chaco cryogenic natural gas processing plant we did not already own, all
of which are located in the San Juan Basin of northwest New Mexico and
southwestern Colorado;

- 100 percent of the Typhoon Oil Pipeline assets located in the Deepwater
Trend area of the Gulf of Mexico. Typhoon Oil was placed in service in
July 2001 and provides transportation of oil produced from the Typhoon
field for delivery to a platform in Green Canyon Block 19 with onshore
access through various oil pipelines;

- 100 percent of the Typhoon Gas Pipeline, which was placed in service in
August 2001. Typhoon Gas is also located in the Deepwater Trend area of
the Gulf of Mexico. The pipeline gathers natural gas from the Typhoon
field for redelivery into El Paso Corporation's ANR Patterson System; and

- 100 percent of the Coastal Liquids Partners' NGL Business, consisting of
an integrated set of NGL assets that stretch from the Mexico border near
McAllen, Texas, to Houston, Texas. This business includes a fractionation
facility near Houston, Texas; a truck-loading terminal near McAllen,
Texas, and leased underground NGL storage facilities.

We purchased the San Juan assets for $782 million, $766 million after
adjustments for capital expenditures and actual working capital acquired. We
financed the purchase of these assets with net proceeds from an offering of $200
million of 10 5/8% Senior Subordinated Notes due 2012, borrowings of $237.5
million under our senior secured acquisition term loan, our issuance, to El Paso
Corporation, of $350 million representing 10,937,500 of our Series C units
valued at $32 per unit and currently available funds. We acquired the San Juan
assets because they are strategically located in active supply development areas
and are supported by long-term contracts that provide us with growing and
reliable cash flows consistent with our stated growth strategy.

In connection with this acquisition, El Paso Corporation is required,
subject to specified conditions, to repurchase the Chaco plant from us for $77
million in October 2021, and at that time we have the right to lease the plant
from them for a period of 10 years with the option to renew the lease annually
thereafter.

As a result of our acquisition of the San Juan assets, our financial
results from the operation of the Chaco plant is significantly different from
our results prior to the purchase as follows:

- We no longer receive fixed fee revenue of $0.134/Dth for natural gas
processed; rather, from a majority of our customers, we receive a
processing fee of an in-kind portion of the NGL produced from the natural
gas processed. We then sell these NGL and now our processing revenues are
affected by changes in the price of NGL.

- We no longer receive revenue for leasing the Chaco plant to El Paso Field
Services.

- We no longer recognize amortization expense relating to our investment in
processing agreement, which we terminated upon completing the
acquisition. This decrease in amortization expense is offset by
additional depreciation expense associated with the acquired assets.

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 approved these transactions.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table summarizes our allocation of the fair values of the
assets acquired and liabilities assumed at November 27, 2002. Our allocation
among the assets acquired is based on the results of an independent third-party
appraisal. The purchase price allocation is subject to modification pending
validation of working capital balances (in thousands):

The acquired intangible assets represent contractual rights we obtained
under dedication and transportation agreements with producers which we are
amortizing to expense using the units-of-production method over the expected
lives of the underlying reserves of approximately 20 years. We recorded
adjustments to the purchase price of approximately $16 million primarily for
capital expenditures and actual working capital acquired. The purchase price
allocation is subject to further adjustment as new information becomes available
regarding the working capital accounts we acquired.

Our consolidated financial statements include the results of operations of
the San Juan assets from the November 27, 2002 purchase date. We have included
the assets and operating results of the El Paso Field Services' San Juan
Gathering and Processing Businesses and the Typhoon Gas Pipeline in our natural
gas pipelines and plants segment and the assets and operating results of the
Typhoon Oil Pipeline and Coastal Liquids Partners' NGL Business in our oil and
NGL logistics segment from the purchase date. The following selected unaudited
pro forma financial information presents our consolidated operating results for
the years ended December 31, 2002 and 2001 as if we acquired the San Juan assets
on January 1, 2001:

The unaudited pro forma financial information presented above is not
necessarily indicative of the results of operations we might have realized had
the transaction been completed at the beginning of the earliest period
presented, nor do they necessarily indicate our consolidated operating results
for any future period.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

EPN Holding Assets

In April 2002, we acquired, through a series of related transactions, from
subsidiaries of El Paso Corporation the following midstream assets located in
Texas and New Mexico, which we collectively refer to as the EPN Holding assets:

- The Waha natural gas gathering and treating system and the Carlsbad
natural gas gathering system which are generally located in the Permian
Basin region of Texas and New Mexico.

- A 50 percent undivided interest in the Channel Pipeline System, an
intrastate natural gas transmission system located along the Gulf Coast
of Texas.

- The TPC Offshore pipeline system, a collection of natural gas gathering
and transmission assets located offshore of Matagorda Bay, Texas,
including the Oyster Lake and MILSP Condensate Separation and
Stabilization facilities and other undivided interests in smaller
pipelines.

- EPGT Texas Pipeline, L.P. which owns, among other assets, (i) the EPGT
Texas intrastate pipeline system, (ii) the TGP natural gas lateral
pipelines, (iii) the leased natural gas storage facilities located in
Wharton County, Texas generally known as the Wilson Storage facility,
(iv) an 80 percent undivided interest in the East Texas 36 inch pipeline,
(v) a 50 percent undivided interest in the West Texas 30 inch pipeline,
(vi) a 50 percent undivided interest in the North Texas 36 inch pipeline,
(vii) the McMullen County natural gas gathering system, (viii) the
Hidalgo County natural gas gathering system, (ix) a 22 percent undivided
interest in the Bethel-Howard pipeline, and (x) a 75 percent undivided
interest in the Longhorn pipeline.

- El Paso Hub Services L.L.C. which owns certain contract rights and
parcels of real property located in Texas.

- 100 percent of the outstanding joint venture interest in Warwink
Gathering and Treating Company which owns among other assets, the Warwink
natural gas gathering system located in the Permian Basin region of Texas
and New Mexico.

In conjunction with the acquisition of the above assets, we obtained from
another affiliate of El Paso Corporation, all of the equity interest in El Paso
Indian Basin, L.P. which owns a 42.3 percent undivided, non-operating interest
in the Indian Basin natural gas processing plant and treating facility located
in southeastern New Mexico and the price risk management activities associated
with the plant.

We acquired the EPN Holding assets to provide us with a significant new
source of cash flow, greater diversification of our midstream asset base and to
provide new long term internal growth opportunities in the Texas intrastate
market. We purchased the EPN Holding assets for $750 million, adjusted for the
assumption of $15 million of working capital related to natural gas imbalances
resulting in net consideration of $735 million comprised of the following:

- $420 million of cash;

- $119 million of assumed short-term indebtedness payable to El Paso
Corporation, which we subsequently repaid;

- $6 million in common units; and

- $190 million in assets, comprised of our Prince TLP and our nine percent
overriding royalty interest in the Prince field (see discussion below).

EPN Holding entered into a limited recourse credit agreement with a
syndicate of commercial banks to finance substantially all of the cash
consideration associated with this transaction. See Note 6 for additional
discussion regarding the EPN Holding term credit facility.

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The following table summarizes our allocation of the fair values of the
assets acquired and liabilities assumed at April 8, 2002. Our allocation among
the assets acquired is based on the results of an independent third-party
appraisal. The purchase price allocation is subject to modification pending
validation of working capital balances (in thousands):

The acquired intangible assets represent contractual rights we obtained
under dedication and transportation agreements with producers which we will
amortize to expense using the units-of-production method over the expected lives
of the underlying reserves ranging from 26 to 45 years. Additionally, we assumed
environmental liabilities of $21.1 million for estimated environmental
remediation costs associated with the EPGT Texas intrastate pipeline assets as
discussed in Note 10.

Our consolidated financial statements include the results of operations of
the EPN Holding assets from the April 8, 2002 purchase date. We have included
the assets and operating results of the Waha, Carlsbad and Warwink natural gas
gathering systems; the Channel and TPC Offshore pipeline systems; and the EPGT
Texas pipeline assets (excluding the Wilson Storage facility) in our natural gas
pipelines and plants segment. Our 42.3 percent ownership interest in the assets
and operating results of the Indian Basin plant are included in our oil and NGL
logistics segment and the Wilson storage facility assets and operating results
are included in our natural gas storage segment. The following selected
unaudited pro forma information depicts our consolidated results of operations
for the years ended December 31, 2002 and 2001 as if we acquired the EPN Holding
assets on January 1, 2001:

In April 2002, we sold the Prince assets for $190 million and recognized a
gain on the sale of $0.4 million during 2002. In conjunction with this
transaction, we repaid the related outstanding $95 million principal balance
under our Argo term loan.

Deepwater Holdings L.L.C. and Chaco Transaction

In October 2001, we acquired the remaining 50 percent interest that we did
not already own in Deepwater Holdings for approximately $81 million, consisting
of $26 million cash and $55 million of assumed indebtedness, and at the
acquisition date also repaid all of Deepwater Holdings $110 million of
indebtedness. HIOS and East Breaks became indirect wholly-owned assets through
this transaction. In a separate transaction, we acquired the Chaco cryogenic
natural gas processing plant for $198.5 million. The total purchase price was
composed of a payment of $77 million to acquire the plant from the bank group
that provided the financing for the construction of the facility and a payment
of $121.5 million to El Paso Field Services in connection with the execution of
a 20-year fee-based processing agreement relating to the processing capacity of
the Chaco plant and dedication of natural gas gathered by El Paso Field Services
to the Chaco plant. Under the terms of the processing agreement, we received a
fixed fee for each dekatherm of natural gas that we processed at the Chaco
plant, and we bore all costs associated with the plant's ownership and
operations. El Paso Field Services personnel continued to operate the plant. In
accordance with the original construction financing agreements, the Chaco plant
was under an operating lease to El Paso Field Services. El Paso Field Services
had the right to repurchase the Chaco Plant at the end of the lease term in
October 2002 for approximately $77 million. We funded both of these transactions
by borrowing from our revolving credit facility. We accounted for these
transactions as purchases and have assigned the purchase price to the net assets
acquired based upon the estimated fair value of the net assets as of the
acquisition date. The operating results associated with Deepwater Holdings are
included in earnings from unconsolidated affiliates for the periods prior to
October 2001. We have included the operating results of Deepwater Holdings and
the Chaco plant in our consolidated financial statements from the acquisition
date.

Since the Chaco transaction was an asset acquisition, we have assigned the
total purchase price to property, plant and equipment and investment in
processing agreement. Since the Deepwater Holdings

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transaction was an acquisition of additional interests in a business, we are
providing summary information related to the acquisition of Deepwater Holdings
in the following table (in thousands):

Fair value of assets acquired............................... $ 81,331
Cash acquired............................................... 5,386
Fair value of liabilities assumed........................... (60,917)
--------
Net cash paid..................................... $ 25,800
========

In connection with our acquisition of the San Juan assets in November 2002,
the original terms of the processing, lease and operating agreements between the
Chaco plant and El Paso Field Services, were terminated. The effect on our
operation of the Chaco plant resulting from our acquisition of the San Juan
assets is discussed above.

EPN Texas

In February 2001, we acquired EPN Texas from a subsidiary of El Paso
Corporation for $133 million. We funded the acquisition of these assets by
borrowing from our revolving credit facility. These assets include more than 500
miles of NGL gathering and transportation pipelines. The NGL pipeline system
gathers and transports unfractionated and fractionated products. We also
acquired three fractionation plants with a capacity of approximately 96 MBbls/d.
These plants fractionate NGL into ethane, propane, butane and natural gasoline
products that are used by refineries and petrochemical plants along the Texas
Gulf Coast. We accounted for the acquisition as a purchase and assigned the
purchase price to the assets acquired based upon the estimated fair value of the
assets as of the acquisition date. We have included the operating results of EPN
Texas in our consolidated financial statements from the acquisition date.

The following selected unaudited pro forma information represents our
consolidated results of operations on a pro forma basis for the twelve months
ended December 31, 2001 and 2000, as if we acquired EPN Texas, the Chaco plant
and the remaining 50 percent interest in Deepwater Holdings on January 1, 2000:

Gulf of Mexico Assets

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

As additional consideration for the above transactions, El Paso Corporation
will make payments to us totaling $29 million. These payments will be made in
quarterly installments of $2.25 million for three years

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beginning in 2001 and ending with a $2 million payment in the first quarter of
2004. From this additional consideration, we realized income of approximately
$25 million in the first quarter of 2001, which has been reflected in other
income in the accompanying statements of income.

Crystal Gas Storage

In August 2000, we acquired the salt dome natural gas storage businesses of
Crystal Gas Storage, Inc., a subsidiary of El Paso Corporation, in exchange for
$170 million of Series B 10% Cumulative Redeemable Preference Units. We
accounted for the acquisition as a purchase and assigned the purchase price to
the assets and liabilities acquired based upon the estimated fair value of those
assets and liabilities as of the acquisition date. We have included the
operating results of Crystal Gas Storage, Inc. in our consolidated financial
statements from the acquisition date. The following is summary information
related to the acquisition (in thousands):

Fair value of assets acquired............................... $170,573
Fair value of liabilities assumed........................... (573)
--------
Preference units issued........................... $170,000
========

El Paso Intrastate-Alabama Pipeline System

In March 2000, we acquired EPIA from a subsidiary of El Paso Corporation
for $26.5 million in cash. We accounted for the acquisition as a purchase and
assigned the purchase price to the assets and liabilities acquired based upon
the estimated fair value of those assets and liabilities as of the acquisition
date. We have included the operating results of EPIA in our consolidated
financial statements from the acquisition date. The following is summary
information related to the acquisition (in thousands):

Fair value of assets acquired............................... $28,261
Fair value of liabilities assumed........................... (1,785)
-------
Net cash paid..................................... $26,476
=======

The following selected unaudited pro forma information represents our
consolidated results of operations on a pro forma basis for the year ended
December 31, 2000, assuming we acquired EPIA and the Crystal natural gas storage
businesses on January 1, 2000:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

3. INVESTMENTS IN UNCONSOLIDATED AFFILIATES

We hold investments in unconsolidated affiliates which are accounted for
using the equity method of accounting. As of December 31, 2002, the carrying
amount of our equity investments exceeded the underlying equity in net assets by
approximately $3.0 million, which is included in our Oil and NGL logistics
segment. With our adoption of SFAS No. 142 on January 1, 2002, we no longer
amortize this excess amount, refer to Note 1, Summary of Significant Accounting
Policies, Goodwill and Other Intangible Assets. Summarized financial information
for these investments is as follows:

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

(a) We acquired an interest in Coyote Gas Treating, L.L.C. in November 2002 as
part of the San Juan assets acquisition.

(b) In June 2002, we formed Deepwater Gateway, L.L.C., a 50/50 joint venture
with Cal Dive International, Inc., to construct and install the Marco Polo
TLP. Also in August 2002, Deepwater Gateway obtained a project finance loan
to fund a substantial portion of the cost to construct the Marco Polo TLP.
For further discussion of this project loan, see Note 6, Financing
Transactions. Deepwater Gateway, L.L.C. is a development stage company;
therefore there are no operating revenues or operating expenses to provide
operational results. Since Deepwater Gateway's formation in 2002, it has
incurred organizational expenses and received interest income.

(c) We recorded adjustments primarily for differences from estimated year end
earnings reported in our Annual Report on our Form 10-K and actual earnings
recorded in the audited annual reports of our unconsolidated affiliates. The
adjustment for Poseidon primarily represents the receipt of proceeds from a
favorable litigation related to the January 2000 pipeline rupture.

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

(a) In January 2001, Deepwater Holdings sold its Stingray and West Cameron
subsidiaries. Deepwater Holdings sold its interest in its UTOS subsidiary in
April 2001. In October 2001, we acquired the remaining 50 percent of
Deepwater Holdings and as a result of this transaction, on a going forward
basis Deepwater Holdings is consolidated in our financial statements. The
information presented for Deepwater Holdings as an equity investment is
through October 18, 2001.
(b) Divested Investments contains Manta Ray Offshore Gathering Company, L.L.C.
and Nautilus Pipeline Company L.L.C. In January 2001, we sold our 25.67
percent interest in Manta Ray Offshore and our 25.67 percent interest in
Nautilus.
(c) Through October 2001 this company processed gas for Deepwater Holdings'
Stingray subsidiary. This agreement was terminated in October 2001, and as
of this date there are no operations related to this investment.
(d) The income (loss) from Deepwater Holdings is not allocated proportionately
with our ownership percentage because the capital contributed by us was a
larger amount of the total capital at the time of formation. Therefore, we
were allocated a larger amount of amortization of Deepwater Holdings' excess
purchase price of its investments. Also, we were allocated a larger portion
of Deepwater Holdings' $21 million loss incurred in 2001 due to the sale of
Stingray, UTOS, and the West Cameron dehydration facility. Our total share
of the losses relating to these sales was approximately $14 million.
(e) We recorded adjustments primarily for differences from estimated year end
earnings reported in our Annual Report on Form 10-K and actual earnings
reported in the audited annual reports of our unconsolidated affiliates.

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

(a) Divested Investments contains Manta Ray Offshore Gathering Company, L.L.C.
and Nautilus Pipeline Company L.L.C. In January 2001, we sold our 25.67
percent interest in Manta Ray Offshore and our 25.67 percent interest in
Nautilus.
(b) We recorded adjustments primarily for differences from estimated year end
earnings reported in our Annual Report on Form 10-K and actual earnings
reported in the audited annual reports of our unconsolidated affiliates, and
for purchase price adjustments under APB Opinion No. 16, "Business
Combinations." The adjustment for Poseidon primarily represents the receipt
or expected receipt of insurance proceeds to offset our share of the repair
costs related to the January 2000 pipeline rupture.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

4. PROPERTY, PLANT AND EQUIPMENT

Our property, plant and equipment consisted of the following:

Due to the sale of our interest in the Manta Ray Offshore system in January
2001, we lost a primary connecting point to our Manta Ray pipeline. As a result,
we abandoned the Manta Ray pipeline and recorded an impairment of approximately
$3.9 million in the first quarter of 2001 which is reflected in the Natural gas
pipelines and plants segment.

5. INVESTMENT IN PROCESSING AGREEMENT

As part of our October 2001 Chaco transaction, we paid $121.5 million to El
Paso Field Services for a 20-year fee-based processing agreement. As a result of
the San Juan acquisition in November 2002, we now own the gathering system and
related facilities previously owned by El Paso Field Services, including the
rights of El Paso Field Services under the arrangements relating to the Chaco
plant. Prior to this acquisition, our investment in the processing agreement was
being amortized on a straight-line basis over the life of the agreement and we
recorded amortization expense of $5.6 million in 2002 and $1.5 million in 2001
related to this asset. Under the processing agreement, all previously
uncommitted volumes on El Paso Field Services' San Juan Gathering System were
dedicated to the Chaco plant. As part of the agreement, natural gas delivered to
the Chaco plant by El Paso Field Services had a processing priority over other
natural gas.

6. FINANCING TRANSACTIONS

In October 2002, we amended the terms of our $600 million revolving credit
facility and the EPN Holding term credit facility in connection with our
entering into the senior secured term loan. The modifications included, among
other things, (1) entering into a new $160 million senior secured term loan
maturing in 2007 as a term component of our revolving credit facility, which we
collectively refer to as our credit facility; (2) designating the EPN Holding
term credit facility as "senior secured" indebtedness, in addition to our credit
facility which is cross-collateralized on an equal basis with all of the
collateral currently pledged under our credit facility and the EPN Holding term
credit facility; (3) aligning, effectively, the covenants in our credit facility
and the EPN Holding term credit facility, including eliminating the restrictions
for distributing cash out of EPN Holding; and (4) terminating the $25 million
revolving credit facility that was formerly part of the EPN Holding term credit
facility.

In November 2002, we further amended our credit facility and the EPN
Holding term credit facility in connection with our borrowing of $237.5 million
under the senior secured acquisition term loan to modify the interest rates the
facilities bear. The modified interest rate we are charged under the terms of
the amendment

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

will remain in effect until the senior secured acquisition term loan is repaid
in full. Under the amended terms of these agreements, the loans bear interest at
our option at either (i) 2.25% plus a variable base rate (equal to the greater
of the prime rate as determined by JP Morgan Chase Bank, the federal funds rate
plus 0.5% or the Certificate of Deposit (CD) rate as determined by JP Morgan
Chase Bank plus 1.00%); or (ii) LIBOR plus 3.50%. Our credit facility, the EPN
Holding term credit facility, senior secured term loan and the senior secured
acquisition term loan are discussed below.

CREDIT FACILITY

Revolving Credit Facility

As of December 31, 2002, we had $491 million outstanding with an average
interest rate of 5.14% under our $600 million revolving credit facility with the
total unused amount available. The applicable rates on our revolving credit
facility will revert to the historical rate schedule at LIBOR plus rates ranging
from 0.875% to 2.50% or one of the variable base rates described above plus
rates ranging from 0.0% to 1.50% following repayment of the $237.5 million
senior secured acquisition term loan, subject to our meeting certain ratios and
attaining certain ratings as set forth in our credit facility. Our interest rate
is contingent upon our leverage ratio, as defined in our credit facility, and
ratings we are assigned by S&P or Moody's on our long-term unsecured debt. The
interest rate we are charged would increase by 0.50% if the credit ratings on
our senior unsecured debt are decreased, or, alternatively, would decrease by
0.25% if these ratings are increased or our leverage ratio improves. We pay
commitment fees on the unused portion of our revolving credit facility at rates
that vary from 0.25% to 0.50% per year. The revolving credit facility matures in
May 2004, is guaranteed by us and all of our subsidiaries, except for our
unrestricted subsidiaries (Matagorda Island Area Gathering System, Arizona Gas
Storage, L.L.C. and EPN Arizona Gas, L.L.C.), El Paso Energy Partners Finance
Corporation and our general partner, and is cross-collateralized with our other
credit facilities by substantially all of our assets (excluding our unrestricted
subsidiaries) and our general partner's general and administrative services
agreement. The covenants and events of default governing the revolving credit
facility are described under Credit Facilities Covenants.

Senior Secured Term Loan

In October 2002, in connection with the amendment of our credit facilities
discussed above, we obtained a $160 million senior secured term loan with a
syndicate of lenders which we used to temporarily reduce indebtedness under our
$600 million revolving credit facility. We may elect that all or a portion of
the senior secured term loan bear interest at either 2.25% plus a variable base
rate (equal to the greater of the prime rate as determined by JP Morgan Chase
Bank, the federal funds rate plus 0.5% or the CD rate as determined by JP Morgan
Chase Bank plus 1%); or LIBOR plus 3.5%. We may, at our option, make prepayments
in amounts not less than $5 million. The senior secured term loan is payable in
semi-annual installments of $2.5 million in April and October of each year
beginning April 2003 for the first nine installments and the remaining balance
at maturity in October 2007. The senior secured term loan is guaranteed by us,
all of our subsidiaries (other than our unrestricted subsidiaries) and our
general partner; and is cross-collateralized with our credit facility, the EPN
Holding term credit facility, and our senior secured acquisition term loan by
substantially all of our assets (excluding our unrestricted subsidiaries) and by
our general partner's general and administrative services agreement. As of
December 2002 we had $160 million outstanding with an average interest rate of
5.22%. The covenants and events of default governing this loan are described
under Credit Facilities Covenants.

EPN Holding Term Credit Facility

In connection with our acquisition of the EPN Holding assets from El Paso
Corporation in April 2002, EPN Holding entered into a $560 million term credit
facility with a group of commercial banks. The term

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

credit facility provided a term loan (the EPN Holding term loan) of $535 million
to finance the acquisition of the EPN Holding assets, and a revolving credit
facility (the EPN Holding revolving credit facility) of up to $25 million to
finance EPN Holding's working capital. EPN Holding's obligations under the term
credit facility are guaranteed by us, all of our subsidiaries (other than our
unrestricted subsidiaries,), El Paso Energy Partners Finance Corporation and our
general partner and is cross-collateralized with our other credit facilities by
substantially all of our assets (excluding our unrestricted subsidiaries) and by
our general partner's general and administrative services agreement. At the time
of its acquisition, EPN Holding borrowed $535 million ($531 million, net of
issuance costs) under this term loan and had $25 million available under the EPN
Holding revolving credit facility which we have subsequently terminated. The EPN
Holding term loan matures in April 2005. We used net proceeds of approximately
$149 million from our April 2002 common unit offering, $0.6 million contributed
by our general partner to maintain its one percent capital account balance and
$225 million of the net proceeds from our May 2002 offering of 8 1/2% Senior
Subordinated Notes to reduce indebtedness under the term loan. As of December
31, 2002, the outstanding balance under the EPN Holding term credit facility was
$160 million with an average interest rate of 4.92%. Following our repayment of
the senior secured acquisition term loan, the interest rate we are charged on
balances outstanding under the EPN Holding term credit facility will revert to
the historical rate schedule at LIBOR plus rates ranging from 1.75% to 2.50% or
one of the variable base rates described above plus rates ranging from 0.50% to
1.25%, subject to our meeting certain ratios set forth in the EPN Holding term
credit facility. The interest rate we are charged would increase by 0.25% if our
leverage ratio deteriorates to 5.00 to 1.00 or greater, or would decrease by
0.25% if our leverage ratio improves to 4.00 to 1.00 or less. The covenants and
events of default governing this credit facility are described under Credit
Facilities Covenants.

Senior Secured Acquisition Term Loan

As part of the San Juan assets acquisition, we entered into a $237.5
million senior secured acquisition term loan to fund a portion of the $766
million purchase price of the San Juan assets. The loan bears interest at our
option at either (i) 2.25% plus a variable rate (equal to the greater of the
prime rate as determined by JP Morgan Chase Bank, the federal funds rate plus
..05% or the CD rate as determined by JP Morgan Chase Bank plus 1%); or (ii)
LIBOR plus 3.5% and is subject to a grid based on our credit ratings. The
interest rate we are charged on balances outstanding under the senior secured
acquisition term loan is dependent on the ratings we are assigned by S&P and
Moody's on our senior secured long-term bank debt. Our interest rate is
increased by 1.00% when our senior secured long-term bank debt is rated below
the higher of BB+ by S&P and Ba1 by Moody's. At December 31, 2002, we had $237.5
million outstanding with an average interest rate of 4.95%. We repaid the senior
secured acquisition term loan in March 2003 with proceeds from our issuance of
$300 million 8 1/2% Senior Subordinated Notes.

Credit Facilities Covenants

Our credit facility, the EPN Holding term credit facility and our senior
secured acquisition term loan contain covenants that include restrictions on our
and our subsidiaries' ability to incur additional indebtedness or liens, sell
assets, make loans or investments, acquire or be acquired by other companies and
amend some of our contracts, as well as requiring maintenance of certain
financial ratios. Failure to comply with the provisions of any of these
covenants could result in acceleration of our debt and other financial
obligations and that of our subsidiaries and restrict our ability to make
distributions to our unitholders. The financial covenants associated with these
facilities are as follows:

(a) Consolidated tangible net worth cannot be less than $710.0 million
plus 75 percent of the net proceeds we receive from future sales or
issuance of any equity securities by us;

(b) The ratio of consolidated EBITDA, as defined in our credit
agreements, to consolidated interest expense cannot be less than 2.0 to
1.0;

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(c) The ratio of consolidated total senior indebtedness on the last
day of any fiscal quarter to the consolidated EBITDA for the four quarters
ending on the last day of the current quarter cannot exceed 3.25 to 1.0;
and

(d) The ratio of our consolidated total indebtedness on the last day
of any fiscal quarter through December 31, 2003 to the consolidated EBITDA
for the four quarters ending on the last day of the current quarter cannot
exceed 5.25 to 1.0. The ratio of consolidated total indebtedness to
consolidated EBITDA will decline to 5.0 to 1.0 beginning January 1, 2004.

Among other things, each credit agreement includes as an event of default
the failure of El Paso Corporation and its subsidiaries to own more than 50
percent of our general partner unless our creditors agree otherwise. We are in
compliance with the financial ratios and covenants contained in each of our
credit facilities at December 31, 2002. We have available for use the entire
$109 million remaining under our revolving credit facility.

SENIOR SUBORDINATED NOTES

Each issue of our senior subordinated notes is subordinated in right of
payment to all existing and future senior debt including our credit facility,
the EPN Holding term credit facility and our senior secured acquisition term
loan. Additionally, our subordinated notes include provisions that, among other
things, restrict our and our subsidiaries ability to acquire assets, incur
additional indebtedness or liens, sell assets, acquire or be acquired by other
companies, and enter into sale and lease-back transactions unless we meet
certain financial ratios and other specific conditions. These restrictive
covenants will be suspended should our notes be rated Baa3 or higher by Moody's
or BBB- or higher by S&P.

In November 2002, we issued $200 million in aggregate principal amount of
10 5/8% Senior Subordinated Notes. These notes bear interest of 10 5/8% per
year, payable semi-annually in June and December, and mature in December 2012.
These notes were issued for $198 million, net of discount of $1.5 million to
yield 10.75% (proceeds of $194 million, net of issuance costs) which we used to
fund a portion of the acquisition of the San Juan assets. These notes are
subject to a registration rights agreement whereby, we are required to register
these notes on Form S-4 with the SEC within 150 days of their issuance or under
certain circumstances be subject to penalties of approximately $10,000 per week
until a registration statement is filed with the SEC and declared effective. On
February 28, 2003, we filed a Form S-4 with the SEC, however, it has not been
declared effective. We may, at our option, prior to December 1, 2005, redeem up
to 33 percent of the originally issued aggregate principal amount of the notes
at a redemption price of 110.625%. On or after December 1, 2007, we may redeem
all or part of these notes at 105.313% of the principal amount.

In May 2002, we issued $230 million in aggregate principal amount of 8 1/2%
Senior Subordinated Notes. These notes bear interest of 8 1/2% per year, payable
semi-annually in June and December, and mature June 2011. The Senior
Subordinated Notes were issued for $234.6 million (proceeds of approximately
$230 million, net of issuance costs). We used proceeds of $225 million to reduce
indebtedness under our EPN Holding term credit facility and the remainder for
general partnership purposes. We may, at our option, prior to June 1, 2004,
redeem up to 33 percent of the originally issued aggregate principal amount of
the senior subordinated notes due June 2011, at a redemption price of 108.500%.
On or after June 1, 2006, we may redeem all or part of these notes at 104.250%
of the principal amount.

In May 2001, we issued $250 million in aggregate principal amount of 8 1/2%
Senior Subordinated Notes. These notes bear interest at a rate of 8 1/2% per
year, payable semi-annually in June and December, and mature in June 2011.
Proceeds of approximately $243 million, net of issuance costs, were used to
reduce indebtedness under our revolving credit facility. We may, at our option,
prior to June 1, 2004, redeem up to 33 percent of the originally issued
aggregate principal amount of the senior subordinated notes due June 2011, at a

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redemption price of 108.500%. On or after June 1, 2006, we may redeem all or
part of these notes at 104.250% of the principal amount.

In May 1999, we issued $175 million in aggregate principal amount of
10 3/8% Senior Subordinated Notes. These notes bear interest at a rate of
10 3/8% per year, payable semi-annually in June and December, and mature in June
2009. Proceeds of approximately $169 million, net of issuance costs, were used
to reduce indebtedness under our revolving credit facility. On or after June 1,
2004, we may redeem all or part of these notes at 105.188% of the principal
amount.

Our subsidiaries, except El Paso Energy Partners Finance Corporation and
our unrestricted subsidiaries, have guaranteed our obligations under all of the
issuances of senior subordinated notes described above. In addition, we could be
required to repurchase the senior subordinated notes if certain circumstances
relating to change of control or asset dispositions exist. We are currently in
compliance with the financial ratios and covenants contained in each of our
senior subordinated notes at December 31, 2002.

ARGO TERM LOAN

This loan with a balance of $95 million, including current maturities, at
December 31, 2001, was repaid in full in April 2002, in connection with the EPN
Holding asset acquisition.

OTHER CREDIT FACILITIES

Poseidon Oil Pipeline Company, L.L.C., an unconsolidated affiliate in which
we have a 36 percent joint venture ownership interest, is party to a $185
million credit agreement under which it has outstanding obligations that may
restrict its ability to pay distributions to its owners.

In January 2002, Poseidon entered into a two-year interest rate swap
agreement to fix the variable LIBOR based interest rate on $75 million of the
$148 million outstanding under its credit facility at 3.49% through January
2004. Poseidon, under its credit facility, currently pays an additional 1.50%
over the LIBOR rate resulting in an effective interest rate of 4.99% on the
hedged notional amount. The interest rates Poseidon is charged on balances
outstanding under its credit facility is dependent on their leverage ratio as
defined in the Poseidon credit facility. Poseidon's interest rate at December
31, 2002 was LIBOR plus 1.50% for Eurodollar loans and a variable base rate
equal to the greater of the prime rate or 0.50% plus the federal funds rate (as
those terms are defined in the Poseidon credit agreement) plus 0.50% for Base
Rate loans. Poseidon's interest rates will decrease by 0.25% if their leverage
ratio declines below 2.00 to 1.00 or by 0.50% if their leverage ratio declines
to 1.00 to 1.00 or less. Additionally, Poseidon pays commitment fees on the
unused portion of the credit facility at rates that vary from 0.25% to 0.375%.
This credit agreement requires Poseidon to maintain a debt service reserve equal
to two quarters interest and is collateralized by substantially all of
Poseidon's assets. As of December 31, 2002, the remaining $73 million was at an
average interest rate of 3.38%.

Poseidon's credit agreement contains covenants such as restrictions on debt
levels, restrictions on liens collateralizing debt and guarantees, restrictions
on mergers and on the sales of assets and dividend restrictions. A breach of any
of these covenants could result in acceleration of Poseidon's debt and other
financial obligations.

Under the Poseidon revolving credit facility, the financial debt covenants
are:

(a) Poseidon must maintain consolidated tangible net worth in an amount
not less than $75 million plus 100% of the net cash proceeds from the
issuance by Poseidon of equity securities of any kind;

(b) the ratio of Poseidon's EBITDA, as defined in Poseidon's credit
agreement, to interest expense paid or accrued during the four
quarters ending on the last day of the current quarter must be at
least 2.50 to 1.00; and

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(c) the ratio of total indebtedness of Poseidon to EBITDA for the four
quarters ending on the last day of the current quarter shall not
exceed 3.00 to 1.00.

Poseidon was in compliance with the above covenants as of December 31,
2002.

In August 2002, Deepwater Gateway, our joint venture that is constructing
the Marco Polo TLP, obtained a $155 million project finance loan from a group of
commercial lenders to finance a substantial portion of the cost to construct the
Marco Polo TLP and related facilities. Deepwater Gateway may elect that all or a
portion of the project finance loan bear interest at either i) LIBOR plus 1.75%
or ii) an alternate base rate (equal to the greater of the prime rate, the base
CD rate plus 1% or the federal funds rate plus 0.5%, as those terms are defined
in the project finance loan agreement) plus 0.75%. Deepwater Gateway must also
pay commitment fees of 0.375% per year on the unused portion of the project
finance loan. The loan is collateralized by substantially all of Deepwater
Gateway's assets. If Deepwater Gateway defaults on its payment obligations under
the project finance 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 at an average interest rate of 3.38%
and had not paid us or any of our subsidiaries any distributions.

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. Upon conversion of the project finance
loan to a term loan, Deepwater Gateway will be required to maintain a debt
service reserve of not less than the projected principal, interest and fees due
on the term loan for the immediately succeeding six month period. In addition,
Deepwater Gateway is prohibited from making distributions until the project
finance loan has been repaid or is converted.

DEBT MATURITY TABLE

Aggregate maturities of the principal amounts of long-term debt and other
financing obligations for the next 5 years and in total thereafter are as
follows (in thousands):

2003...................................................... $ 5,000
2004...................................................... 733,500
2005...................................................... 165,000
2006...................................................... 5,000
2007...................................................... 140,000
Thereafter.................................................. 855,000
----------
Total long-term debt and other financing
obligations, including current maturities........ $1,903,500
==========

In March 2003, we issued $300 million in aggregate principal amount of
8 1/2% Senior Subordinated Notes. These notes bear interest of 8 1/2% per year,
payable semi-annually in June and December and matures in June 2010. These notes
were issued at par and were used to repay the $238 million senior secured
acquisition term loan and temporarily reduce our revolving credit facility.

INTEREST EXPENSE

We recognized the interest cost incurred in connection with our financing
transactions as follows for each of the years ended:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

7. FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

The carrying amounts and estimated fair values of our financial instruments
at December 31 are as follows:

The notional amounts and terms of contracts held for purposes other than
trading were as follows at December 31:

As of December 31, 2002, and 2001, our carrying amounts of cash and cash
equivalents, short-term borrowings, and trade receivables and payables are
representative of fair value because of the short-term nature of these
instruments. The fair value of long-term debt with variable interest rates
approximates its carrying value because the variable interest rates on these
loans reprice frequently to reflect currently available interest rates. We
estimated the fair value of debt with fixed interest rates based on quoted
market prices for the same or similar issues. We estimated the fair value of all
derivative financial instruments from prices indicated for the same or similar
commodity transactions for a specific index.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Credit Risk

Credit risk relates to the risk of loss that we would incur as a result of
our customers' failure to pay. Our customers are concentrated in the energy
sector, and the creditworthiness of several industry participants have been
called into question. We maintain credit policies to minimize overall credit
risk. We monitor our exposure to and determine, as appropriate, whether we
should request prepayments, letters of credit or other collateral from our
counterparties.

8. PARTNERS' CAPITAL

General

As of December 31, 2002, we had 44,030,314 common units outstanding. Common
units totaling 32,356,069 are owned by the public, representing a 73.5 percent
common unit interest in us. As of December 31, 2002, El Paso Corporation,
through its subsidiaries, owned 11,674,245 common units, or 26.5 percent of our
outstanding common units, all of our 125,392 Series B preference units (with a
liquidation value of $158 million), all of our 10,937,500 Series C units and our
one percent general partner interest.

Offering 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 rights under our
partnership agreement) as a transaction not involving a public offering. We used
the net cash proceeds of approximately $149 million to reduce indebtedness under
EPN Holding's 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 April 2002 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 rights under our
partnership agreement) as a transaction not involving a public offering. We used
the net cash proceeds of approximately $212 million to redeem 44,608 of our
Series B preference units for their liquidation value of $50 million and to
reduce the balance outstanding under our revolving credit facility. In addition,
our general partner contributed $2.1 million in cash to us in order to satisfy
its one percent 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. We
used the net cash proceeds of $101 million 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.

Conversion and Redemption of Preference Units

In May 1998, 1999 and 2000, we notified the holders of our publicly-held
preference units of their opportunity to convert their preference units into an
equal number of common units. Total preference units of 211,249 were converted
to common units after the 90-day conversion period in 2000 and 78,450 preference
units remained. In October 2000, we redeemed the remainder of these preference
units for approximately

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

$0.8 million representing a cash price of $10.25 per unit. For the converted
units, we reallocated the partners' capital accounts in the conversion period to
reflect these conversions of preference units into common units.

Series B Preference Units

In August 2000, we issued 170,000 Series B preference units with a value of
$170 million to acquire the Petal and Hattiesburg natural gas storage
businesses. In October 2001, we redeemed 44,608 of the Series B preference units
for $50 million liquidation value including accrued distributions of
approximately $5.4 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. 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. These preference units contain no mandatory
redemption obligation, but may be redeemed at our option at any time. If our
capital was ever liquidated, then these Series B preference units would have
priority after our general partner, but before our outstanding common
unitholders.

Series C Units

In November 2002, we issued to a subsidiary of El Paso Corporation
10,937,500 of Series C units at a price of $32 per unit, $350 million in the
aggregate, as part of our consideration paid for the San Juan assets. The
issuance of the Series C units was an exempt transaction under Section 4(2) of
the Securities Act of 1993 as a transaction not involving a public offering. The
Series C units are similar to our existing common units, except that the Series
C units are non-voting. After April 30, 2003, the holder of the Series C units
will have the right to cause us to propose a vote of our common unitholders as
to whether the Series C units should be converted into common units. If our
common unitholders approve the conversion, then each Series C unit can convert
into a common unit. If our common unitholders do not approve the conversion
within 120 days after the vote is requested, then the distribution rate for the
Series C units will increase to 105 percent of the common unit distribution rate
in effect from time to time. Thereafter, the Series C unit distribution rate
will increase on April 30, 2004, to 110 percent of the common unit distribution
rate and on April 30, 2005, to 115 percent of the common unit distribution rate.
In addition, our general partner contributed $3.5 million to us in order to
satisfy its one percent capital contribution requirement.

Cash Distributions

We make quarterly distributions of 100 percent of our available cash, as
defined in the partnership agreement, to our unitholders and to our general
partner. Available cash generally consists 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 for any proper
partnership purpose. 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 our agreements or obligations. Beginning in
the fourth quarter of 2010, any unpaid accruals on our Series B preference units
occurring after September 2010 will be currently payable and must be completely
paid, prior to any distributions on our common units.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Cash distributions on common units, Series C units and to our general
partner are discretionary in nature and are not entitled to arrearages of
minimum quarterly distributions. The following table reflects our per unit cash
distributions to our common unitholders and the total incentive distributions
paid to our general partner during the year ended December 31, 2002:

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

(1) Our Series C units are not included in the above table since they did not
receive a distribution until February 2003.

In January 2003, we declared a cash distribution of $0.675 per common and
Series C unit, $37.1 million in aggregate, which we paid on February 14, 2003.
In addition, we paid distributions to our general partner of $14.6 million in
respect of its general partner interest. At the current distribution rates, our
general partner receives approximately 29 percent of our total cash
distributions for its role as our general partner.

Option Plans

In August 1998, we adopted the 1998 Omnibus Compensation Plan (Omnibus
Plan) to provide our general partner with the ability to issue unit options to
attract and retain the services of knowledgeable officers and key management
personnel. Unit options to purchase a maximum of 3 million common units may be
issued pursuant to the Omnibus Plan. Unit options granted to date pursuant to
the Omnibus Plan are not immediately exercisable. For unit options granted in
2001, one-half of the unit options are considered vested and exercisable one
year after the date of grant and the remaining one-half of the unit options are
considered vested and exercisable one year after the first anniversary of the
date of grant. These unit options expire ten years from such grant date, but
shall be subject to earlier termination under certain circumstances. No grants
of unit options were made in 2002.

In August 1998, we also adopted the 1998 Unit Option Plan for Non-Employee
Directors (Director Plan) to provide our general partner with the ability to
issue unit options to attract and retain the services of knowledgeable
directors. Unit options and restricted units to purchase a maximum of 100,000 of
our common units may be issued pursuant to the Director Plan. Under the Director
Plan, each non-employee director receives a grant of 2,500 unit options upon
initial election to the Board of Directors and an annual unit option grant of
2,000 unit options and, beginning in 2001, an annual restricted unit grant equal
to the director's annual retainer (including Chairman's retainers, if
applicable) divided by the fair market value of the common units on the grant
date upon each re-election to the Board of Directors. Each unit option that is
granted will vest immediately at the date of grant and will expire ten years
from such date, but will be subject to earlier termination in the event that
such non-employee director ceases to be a director of our general partner for
any reason, in which case the unit options expire 36 months after such date
except in the case of death, in which case the unit options expire 12 months
after such date. Each director receiving a grant of restricted units is recorded
as a unitholder and has all the rights of a unitholder with respect to such
units, including the right to distributions on those units. The restricted units
are nontransferable during the director's service on the Board of Directors. The
restrictions on the restricted units will end and the director will receive one
common unit for each restricted unit granted upon the director's termination.
The Director Plan is administered by a management committee consisting of the
Chairman of the Board of Directors of the general partner and such other senior
officers of our general partner or its affiliates as the Chairman may designate.
Restricted units

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

awards representing 5,429 and 4,090 were granted during 2002 and 2001 with a
grant price of $32.23 and $33.00 per unit. No restricted units were granted in
2000. As of December 31, 2002, 7,066 restricted units were outstanding. The
value of these units is determined based on the fair market value on the grant
date and this cost is amortized to compensation expense over the period of
service, which we have estimated to be one year.

We have reflected the issuance of the restricted units as deferred
compensation and as an increase in common units. This deferred compensation was
approximately $175 thousand and $135 thousand in 2002 and 2001. Our 2001
deferred compensation is fully amortized. The unamortized amount of our total
deferred compensation as of December 31, 2002, was approximately $1.2 million.

The following table summarizes activity under the Omnibus Plan and Director
Plan (excluding our restricted units) as of and for the years ended December 31,
2002, 2001 and 2000.

The fair value of each unit option granted is estimated on the date of
grant using the Black-Scholes option-pricing model with the following weighted
average assumptions:

The Black-Scholes weighted average fair value of options granted during
2002, 2001, and 2000 was $3.71, $2.62, and $2.63 per unit option, respectively.

Options outstanding as of December 31, 2002, are summarized below:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

9. RELATED PARTY TRANSACTIONS

The majority of our related party transactions are with affiliates of our
general partner. Under an agreement that was in place before an indirect
subsidiary of El Paso Corporation purchased our general partner, an affiliate
our general partner was obligated to provide individuals to perform the day to
day financial, administrative, accounting and operational functions for us. As
our activities increased, the fee for such services has also increased. Further,
we provide services to various El Paso subsidiaries and, in turn, they provide
us services. In addition, we have acquired a number of assets from subsidiaries
of El Paso Corporation.

The following table provides summary data for the income statement impacts
of our transactions with related parties for the years ended December 31:

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

(1) In addition to revenues from continuing operations reflected above, we also
received revenues from related parties in 2002 and 2001 of $6.8 million and
$8.2 million for our Prince TLP and $1.0 million and $0.7 million for our 9
percent overriding royalty interest which are included in income from
discontinued operations on our income statements.

For the years ended December 31, 2002, 2001 and 2000, revenues received
from related parties consisted of approximately 42%, 28% and 24% of our revenue
from continuing operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table provides summary data categorized by our related
parties for the years ended December 31:

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

(1) In addition to revenues from continuing operations from El Paso Production
Company reflected above, during 2002 and 2001 we also received revenues of
$7.8 million and $8.9 million from El Paso Production Company which are
included in income from discontinued operations in our income statements.

(2) We sold our interest in Manta Ray Offshore in January 2001 in connection
with El Paso Corporation's merger with the Coastal Corporation.

(3) In January 2001, Deepwater Holdings sold its Stingray and West Cameron
subsidiaries. In April 2001, Deepwater Holdings sold its UTOS subsidiary. In
October 2001, we acquired the remaining 50 percent of Deepwater Holdings,
and as a result of this transaction, on a going forward basis, Deepwater
Holdings is consolidated in our financial statements and our agreement with
Deepwater Holdings terminated.

Revenues received from related parties

EPN Holding Assets. Our revenues from related parties increased in 2002 as
a result of our EPN Holding transaction in which we acquired gathering,
transportation and processing contracts with affiliates of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

our general partner. For the year ended December 31, 2002, we received $68.9
million from El Paso Merchant Energy North America Company, $35.8 million from
El Paso Field Services and $4.0 million from El Paso Production Company.

EPN Texas. In connection with our acquisition of EPN Texas in February
2001, we entered into a 20-year fee-based transportation and fractionation
agreement with El Paso Field Services. Pursuant to this agreement, we 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. For the years ended December 31, 2002 and 2001, we
received revenue of approximately $26.0 million and $25.2 million related to
this agreement.

Chaco processing plant. In connection with our Chaco transaction in
October 2001, we entered into a 20-year fee-based processing agreement with El
Paso Field Services. Pursuant to this agreement, we receive a fixed fee for each
dekatherm of natural gas that we process at the Chaco plant. For the years ended
December 31, 2002 and 2001, we received revenue of $29.6 million and $6.5
million related to this agreement. In accordance with the original construction
financing agreements, the Chaco plant is under an operating lease to El Paso
Field Services. For the years ended December 31, 2002 and 2001, we received $1.8
million and $0.6 million related to this lease. As a result of the San Juan
asset acquisition, the processing agreement and the operating lease were
terminated.

Storage facilities. With the April 2002 acquisition of the EPN Holding
assets, we purchased contracts held by Wilson Storage with El Paso Merchant
Energy North America Company. For the year ended December 31, 2002 we received
approximately $2.9 million from El Paso Merchant Energy North America Company
for natural gas storage fees. El Paso Merchant Energy North America Company and
Tennessee Gas Pipeline Company use our Petal and Hattiesburg storage facilities
from time to time. For the years ended December 31, 2002, 2001, and the four
months ended December 31, 2000 we received approximately $0.1 million, $1.6
million and $1.2 million from El Paso Merchant Energy North America Company for
natural gas storage fees. For the years ended December 31, 2001, and the four
months ended December 31, 2000 we received approximately $0.7 million and $0.1
million from Tennessee Gas Pipeline Company.

Prince TLP. In September 2001, we placed our Prince TLP in service. Prior
to April 1, 2002, we received a monthly demand charge of approximately $1.9
million as well as processing fees from El Paso Production Company related to
production on the Prince TLP. For the year ended December 31, 2002 and the four
months ended December 31, 2001, we received $6.8 million and $8.2 million in
platform revenue related to this agreement. In connection with our acquisition
of the EPN Holding assets from El Paso Corporation, in April 2002 we sold our
Prince TLP to subsidiaries of El Paso Corporation and these revenues are
reflected in our income from discontinued operations.

Production fields. Through 2000 we had agreed to sell substantially all of
our oil and natural gas production to El Paso Merchant Energy North America
Company on a month to month basis. The agreement provided fees equal to two
percent of the sales value of crude oil and condensate and $0.015 per dekatherm
of natural gas for marketing production. During the year ended December 31,
2000, oil and natural gas sales related to this agreement totaled approximately
$15.7 million. Beginning in the fourth quarter of 2000, we began selling our oil
and natural gas directly to third parties and our oil and natural gas sales
related to El Paso Merchant Energy North America Company were approximately $9.8
million and $5.7 million for years ended December 31, 2002 and 2001.

In October 1999, we farmed out our working interest in the Prince Field to
El Paso Production Company. Under the terms of the farmout agreement, our net
overriding royalty interest in the Prince Field increased to a weighted average
of approximately nine percent. El Paso Production Company began production on
the Prince Field in September 2001. For the year ended December 31, 2002 and the
four months ended

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

December 31, 2001, we recorded approximately $1.0 million and $0.7 million in
revenues related to our overriding royalty interest in the Prince Field. In
connection with our acquisition of the EPN Holding assets from El Paso
Corporation, in April 2002 we sold our 9 percent overriding royalty interest in
the Prince Field to subsidiaries of El Paso Corporation and these revenues are
reflected in our income from discontinued operations.

EPIA. In March 2000, we acquired EPIA. Several El Paso Corporation
subsidiaries buy and transport natural gas on our EPIA system. For the years
ended December 31, 2002, 2001 and 2000, we received approximately $6.8 million,
$8.3 million and $4.9 million from El Paso Merchant Energy North America
Company. For the years ended December 31, 2002, 2001 and 2000, we received
approximately $4.5 million, $4.2 million and $4.3 million from El Paso
Production Company. For the years ended December 31, 2002, 2001 and 2000, we
received approximately $0.1 million, $0.2 million and $0.2 million from Southern
Natural Gas Company.

HIOS. In October 2001, HIOS became a wholly-owned asset through our
acquisition of the remaining 50 percent equity interest in Deepwater Holdings.
HIOS is a natural gas transmission system that has entered into interruptible
transportation agreements at a non-discounted rate of $0.1244. For the year
ended December 31, 2002 and approximately three months ended December 31, 2001,
we received $1.4 million and $0.8 million from El Paso Merchant Energy. For the
year ended December 31, 2002, we received $0.6 million from El Paso Production
Company.

Texas NGL assets. In connection with our acquisition of the San Juan
assets in November, 2002, we entered into a 10-year transportation agreement
with El Paso Field Services. Pursuant to this agreement, beginning January 1,
2003, we receive a fee of $1.5 million per year for transportation on our NGL
pipeline which extends from Corpus Christi to near Houston. In addition, we
provide transportation, fractionation, storage and terminaling services to El
Paso Field Services, as well as to various third parties, typically under
agreements of one year term or less. We received approximately $0.3 million in
revenues from El Paso Field Services for the year ended December 31, 2002.

Other. In addition to the revenues discussed above, we received $2.6
million from El Paso Merchant North America and $3.3 million from El Paso Field
Services during 2002 for additional gathering and processing services.

Unconsolidated Subsidiaries. For the years ended December 31, 2001 and
2000, we received approximately $0.03 million and $0.1 million from Manta Ray
Offshore Gathering as platform access and processing fees related to our South
Timbalier 292 platform and our Ship Shoal 332 platform. We sold our interest in
Manta Ray Offshore in January 2001 in connection with El Paso's merger with the
Coastal Corporation.

Expenses paid to related parties

Cost of natural gas. Our cost of natural gas paid to related parties
increased in 2002 as a result of our EPN Holding transaction in which we
acquired contracts with affiliates of our general partner. For the year ended
December 31, 2002, our EPN Holding assets had cost of natural gas expenses of
$0.3 million for the Waha facility from El Paso Merchant Energy North America
Company and $0.4 million from El Paso Field Services relating to the EPGT
gathering system. EPIA's purchases of natural gas include transactions with
affiliates of our general partner. For the years ended December 31, 2002, 2001
and 2000, we had natural gas purchases of approximately $18.9 million, $28.2
million and $14.4 million from El Paso Merchant Energy North America Company,
$2.3 million, $6.4 million and $2.2 million from El Paso Production Company and
$0.2 million, $0.2 million and $0.1 million from Southern Natural Gas Company.
We also receive lease and throughput fees from El Paso Field Services for
Hattiesburg and Anse La Butte. For the year ended December 31, 2002 we received
$0.5 million from El Paso Field Services related to these fees.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Operating Expenses. Substantially all of the individuals who perform the
day-to-day financial, administrative, accounting and operational functions for
us, as well as those who are responsible for directing and controlling us, are
currently employed by El Paso Corporation. Under a general and administrative
services agreement between subsidiaries of El Paso Corporation and us, a fee of
approximately $0.8 million per month was charged to our general partner, and
accordingly, to us, which is intended to approximate the amount of resources
allocated by El Paso Corporation and its affiliates in providing various
operational, financial, accounting and administrative services on behalf of our
general partner and us. In April 2002, in connection with our acquisition of EPN
Holding assets, our general and administrative services agreement was extended
to December 31, 2005, and the fee increased to approximately $1.6 million per
month. In November 2002, as a result of the San Juan assets acquisition, the
monthly fee under our general and administrative services agreement increased by
$1.3 million, bringing our total monthly fee to $2.9 million. We believe this
fee approximates the actual costs incurred. Under the terms of the partnership
agreement, our general partner is entitled to reimbursement of all reasonable
general and administrative expenses and other reasonable expenses incurred by
our general partner and its affiliates for, or on our behalf, including, but not
limited to, amounts payable by our general partner to El Paso Corporation under
its management agreement. We are also charged for insurance and other costs paid
directly by El Paso Field Services on our behalf.

As we became operator of additional facilities or systems, acquired new
operations or constructed new facilities, we entered into additional management
and operating agreements with El Paso Field Services. All fees paid under these
contracts approximate actual costs incurred.

The following table shows the amount El Paso Field Services charged us for
each of our agreements for the year ended December 31:

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

(1) Operating fees increased from 2001 to 2002 due to the acquisition of the San
Juan assets and EPN Holding assets. The increase from 2000 to 2001 is due to
the EPN Texas asset acquisition.

Poseidon charges were for transportation services related to transporting
production from our Garden Banks Block 72 and 117 leases.

Cost Reimbursements. In connection with becoming the operator of Poseidon,
we entered into an operating agreement in January 2001. For the year ended
December 31, 2000, we charged Manta Ray Offshore a management fee pursuant to
its management and operations agreements. All fees received under contracts
approximate actual costs incurred.

As a result of becoming the operator of Deepwater Holdings' assets during
1999 and 2000, we began receiving reimbursement from Deepwater Holdings for the
cost of operating HIOS, UTOS, East Breaks, Stingray, and the West Cameron
dehydration facility. This reimbursement was a fixed monthly amount covering
normal operating activities that was approved by each subsidiary's management
committee and was based on historical operating expenses. We recorded these as a
reduction to our operation and maintenance expense. To the extent our costs were
more than the monthly reimbursement, our operating expenses were higher, and to
the extent our costs were lower than the monthly reimbursement, our operating
expense were lower. In addition, due to the timing of actual costs, we
recognized fluctuations in our results of operations throughout the years.

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Acquisitions

We have purchased assets from related parties. See Note 2 for a discussion
of these asset acquisitions.

Other Matters

In addition to the related party transactions discussed above, pursuant to
the terms of many of the purchase and sale agreements we have entered into with
various entities controlled directly or indirectly by El Paso Corporation, we
have been indemnified for potential future liabilities, expenses and capital
requirements above a negotiated threshold. Specifically, an indirect subsidiary
of El Paso Corporation has agreed to indemnify us for specific litigation
matters to the extent the ultimate resolutions of these matters result in
judgments against us. For a further discussion of these matters see Note 10,
Commitments and Contingencies, Legal Proceedings. Some of our agreements
obligate certain indirect subsidiaries of El Paso Corporation to pay for capital
costs related to maintaining assets which were acquired by us, if such costs
exceed negotiated thresholds. We do not believe these thresholds will be
exceeded. We have made no such claims for reimbursement to date and none are
contemplated to be made at this time.

We have also entered into contracts with El Paso Merchant Energy for
transportation and storage. El Paso Corporation announced on November 8, 2002
its intention to exit the energy trading business which is party to these
contracts. El Paso Merchant Energy North America Company could sell or transfer
to third parties the natural gas transportation and storage agreements they have
with us, or El Paso Merchant Energy North America Company could request a
cancellation of the transportation and storage agreements. In 2002, these
agreements represented revenue of approximately $33 million. At present, El Paso
Merchant Energy North America Company continues to fully utilize these
agreements.

We have also entered into capital contribution arrangements with regulated
pipelines owned by El Paso Corporation in the past, and will most likely do so
in the future, as part of our normal commercial activities in the Gulf of
Mexico. Regulated pipelines often contribute capital toward the construction
costs of gathering facilities owned by others which are connected to their
pipelines. We have agreements with ANR Pipeline Company and Tennessee Gas
Pipeline Company under which we will receive a total of approximately $12
million of capital toward the construction of gathering pipelines to the Marco
Polo and Medusa discoveries, payable over the next eighteen months. We will
account for these payments as a reduction in property, plant and equipment. As
of December 31, 2002, we received approximately $2 million from ANR Pipeline
Company as contributions in aid of construction of the Marco Polo pipeline.

At December 31, 2002 and 2001, our accounts receivable due from related
parties was $83.8 million and $23.0 million. At December 31, 2002 and 2001, our
accounts payable due to related parties was $86.1 million and $10.1 million.

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Our accounts receivable due from related parties consisted of the following
as of:

- ----------

(1) The December 2002 receivable balance includes approximately $15 million of
natural gas imbalances relating to our EPN Holding acquisition.

Our accounts payable due to related parties consisted of the following as
of:

- ----------

(1) The December 2002 payable balance includes approximately $19 million of
working capital adjustments relating to our EPN Holding acquisition due to
El Paso Field Services; and approximately $22 million of natural gas
imbalances relating to our EPN Holding acquisition.

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In connection with the San Juan assets acquisition in November 2002, we
acquired a 50 percent interest in Coyote Gas Treating LLC. As part of this
transaction we assumed a note receivable due from our unconsolidated affiliate,
Coyote, for $17.1 million.

In connection with the sale of our Gulf of Mexico assets in January 2001,
El Paso Corporation agreed to make quarterly payments to us of $2.25 million for
three years beginning March 2001 and ending with a $2 million payment in the
first quarter of 2004. The present value of the amounts due from El Paso
Corporation were classified as follows:

10. COMMITMENTS AND CONTINGENCIES

Legal Proceedings

Grynberg. In 1997, we were named defendants in actions brought by Jack
Grynberg on behalf of the U.S. Government under the False Claims Act. Generally,
these complaints allege an industry-wide conspiracy to underreport the heating
value as well as the volumes of the natural gas produced from federal and Native
American lands, which deprived the U.S. Government of royalties. The plaintiff
in this case seeks royalties that he contends the government should have
received had the volume and heating value of natural gas produced from royalty
properties been differently measured, analyzed, calculated and reported,
together with interest, treble damages, civil penalties, expenses and future
injunctive relief to require the defendants to adopt allegedly appropriate gas
measurement practices. No monetary relief has been specified in this case. These
matters have been consolidated for pretrial purposes (In re: Natural Gas
Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming,
filed June 1997). In May 2001, the court denied the defendants' motions to
dismiss. Discovery is proceeding.

Will Price (formerly Quinque). We have also been named defendants in
Quinque Operating Company, et al v. Gas Pipelines and Their Predecessors, et al,
filed in 1999 in the District Court of Stevens County, Kansas. Quinque has been
dropped as a plaintiff and Will Price has been added. This class action
complaint alleges that the defendants mismeasured natural gas volumes and
heating content of natural gas on non-federal and non-Native American lands. The
plaintiff in this case seeks certification of a nationwide class of gas working
interest owners and gas royalty owners to recover royalties that the plaintiff
contends these owners should have received had the volume and heating value of
natural gas produced from their properties been differently measured, analyzed,
calculated and reported, together with prejudgment and postjudgment interest,
punitive damages, treble damages, attorney's fees, costs and expenses, and
future injunctive relief to require the defendants to adopt allegedly
appropriate gas measurement practices. No monetary relief has been specified in
this case. Plaintiffs motion for class certification has been argued and we are
awaiting a ruling.

Our Argo L.L.C. subsidiary received a claim from its contractor related to
the Prince TLP. The contractor received a request for additional payments from
its subcontractor as a result of variation orders and was seeking to pass these
costs along to Argo. After negotiations, the contractor, the subcontractor and
Argo agreed upon a settlement in July 2002. This settlement did not have a
material adverse effect on our financial position, results of operations or cash
flow.

Under the terms of our agreement with El Paso Corporation pursuant to which
we acquired the EPN Holding assets, subsidiaries of El Paso Corporation have
agreed to indemnify us against all obligations related

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to existing legal matters at the acquisition date, including the legal matters
involving Leapartners, L.P., City of Edinburg, Houston Pipe Line Company LP and
City of Corpus Christi discussed below.

During 2000, Leapartners, L.P. filed a suit against El Paso Field Services
and others in the District Court of Loving County, Texas, alleging a breach of
contract to gather and process gas in areas of western Texas related to an asset
now owned by EPN Holding. In May 2001, the court ruled in favor of Leapartners
and entered a judgment against El Paso Field Services of approximately $10
million. El Paso Field Services has filed an appeal with the Eighth Court of
Appeals in El Paso, Texas. Briefs have been filed and oral arguments were heard
in November 2002. Review by the Court of Appeals is expected in early 2003.

Also, EPGT Texas Pipeline L.P., now owned by EPN Holding, is involved in
litigation with the City of Edinburg concerning the City's claim that EPGT Texas
was required to pay pipeline franchise fees under a contract the City had with
Rio Grande Valley Gas Company, which was previously owned by EPGT Texas and is
now owned by Southern Union Gas Company. An adverse judgment against Southern
Union and EPGT Texas was rendered in Hidalgo County State District court in
December 1998 and found a breach of contract, and held both EPGT Texas and
Southern Union jointly and severally liable to the City for approximately $4.7
million. The judgment relies on the single business enterprise doctrine to
impose contractual obligations on EPGT Texas and Southern Union's entities that
were not parties to the contract with the City. EPGT Texas has appealed this
case to the Texas Supreme Court seeking reversal of the judgment rendered
against EPGT Texas. The City seeks a remand to the trial court of its claim of
tortious interference against EPGT Texas. Briefs have been filed and oral
arguments were held in November 2002, and we are awaiting a decision.

In December 2000, a 30-inch natural gas pipeline jointly owned by El Paso
Energy Intrastate, now owned by EPN Holding, and Houston Pipe Line Company LP
ruptured in Mont Belvieu, Texas, near Baytown, resulting in substantial property
damage and minor physical injury. El Paso Energy Intrastate is the operator of
the pipeline. In December 2000 a lawsuit was filed in the state district court
in Chambers County, Texas by eight plaintiffs, including two homeowners'
insurers. The suits seek recovery for physical pain and suffering, mental
anguish, physical impairment, medical expenses, and property damage. Houston
Pipe Line Company has been added as an additional defendant. In accordance with
the terms of the operating agreement, El Paso Energy Intrastate has agreed to
assume the defense of and to indemnify Houston Pipe Line Company. In September
2002, an agreement was reached to settle the claims of two plaintiffs (including
one of the insurers). The discovery phase of the lawsuit is proceeding and trial
is expected in early 2003.

The City of Corpus Christi, Texas ("City") is alleging that EPGT Texas and
various Coastal entities owe it monies for past obligations under City
ordinances that propose to tax EPGT Texas on its gross receipts from local
natural gas sales for the use of street rights-of-way. No lawsuit has been filed
to date. Some but not all of the EPGT Texas pipe at issue has been using the
rights-of-way since the 1960's. In addition, the City demands that EPGT Texas
agree to a going-forward consent agreement in order for EPGT Texas pipe and
Coastal to have the right to remain in City rights-of-way.

In addition to the above matters, we and our subsidiaries and affiliates
are named defendants in numerous lawsuits and governmental proceedings that
arise in the ordinary course of our business.

For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we will establish the necessary
accruals. As of December 31, 2002, we had no reserves for our legal matters.

While the outcome of our outstanding legal matters cannot be predicted with
certainty, based on information known to date, we do not expect the ultimate
resolution of these matters will have a material adverse effect on our financial
position, results of operations or cash flows. As new information becomes

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

available or relevant developments occur, we will establish accruals as
appropriate. The impact of these changes may have a material effect on our
results of operations.

Environmental

Each of our operating segments is subject to extensive federal, state, and
local laws and regulations governing environmental quality and pollution
control. These laws and regulations are applicable to each segment and 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. As of December
31, 2002, we had a reserve of approximately $21 million for remediation costs
expected to be incurred over time associated with mercury meters. We assumed
this liability in connection with our April 2002 acquisition of the EPN Holding
assets. El Paso Corporation has agreed to indemnify us for all the known and
unknown environmental liabilities related to the assets we purchased as part of
the San Juan assets acquisition up to the purchase price of $766 million. We
will only be indemnified for unknown liabilities for up to three years from the
purchase date. In addition, we have been indemnified by third parties for
remediation costs associated with other assets we have purchased. Also, 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.

While the outcome of our outstanding environmental matters cannot be
predicted with certainty, based on the information known to date and our
existing accruals, we do not expect the ultimate resolution of these matters
will have a material adverse effect on our financial position, results of
operations or cash flows. It is possible that new information or future
developments could require us to reassess our potential exposure related to
environmental matters. It is also possible that other developments, such as
increasingly strict environmental laws and regulations and claims for damages to
property, employees, other persons and the environment resulting from our
current or past operations, could result in substantial costs and liabilities in
the future. As new information becomes available, or relevant developments
occur, we will review our accruals and make any appropriate adjustments. While
there are still uncertainties relating to the ultimate costs we may incur, based
upon our evaluation and experience to date, we believe our current reserves are
adequate.

Rates and Regulatory Matters

Marketing Affiliate NOPR. In September 2001, the Federal Energy Regulatory
Commission (FERC) issued a Notice of Proposed Rulemaking (NOPR). The NOPR
proposes to apply the standards of conduct governing the relationship between
interstate pipelines and marketing affiliates to all energy affiliates. Since
our High Island Offshore System (HIOS) and Petal Gas Storage facility are
interstate facilities as defined by the Natural Gas Act, the proposed
regulations, if adopted by FERC, would dictate how HIOS and Petal conduct
business and interact with all of our energy affiliates and El Paso
Corporation's energy affiliates. In December 2001, we filed comments with the
FERC addressing our concerns with the proposed rules. A public hearing was held
in May 2002, providing an opportunity to comment further on the NOPR. Following
the conference, additional comments were filed by us. At this time, we cannot
predict the outcome of the NOPR, but adoption of the regulations in the form
proposed would, at a minimum, place additional administrative and operational
burdens on us.

If the standards of conduct NOPR is adopted by the FERC, we will be
required to functionally separate our HIOS and Petal interstate facilities from
our other entities. Under the proposed rule, we would be required to dedicate
employees to manage and operate our interstate facilities independently from our
other non-jurisdictional facilities. This employee group would be required to
function independently and would be prohibited from communicating non-public
transportation information to affiliates. Separate office facilities and systems
would be necessary because of the requirement to restrict affiliate access to
interstate transportation information. The NOPR also limits the sharing of
employees and officers with non-regulated entities. Because of the loss of
synergies and shared employee restrictions, a disposition of the interstate

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facilities may be necessary for us to effectively comply with the rule. At this
time, we cannot predict the outcome of this NOPR.

Negotiated Rate NOI. In July 2002, the FERC issued a Notice of Inquiry
(NOI) that seeks comments regarding its 1996 policy of permitting pipelines to
enter into negotiated rate transactions. The FERC is now reviewing whether
negotiated rates should be capped, whether or not the "recourse rate" (a cost of
service based rate) continues to safeguard against a pipeline exercising market
power, as well as other issues related to negotiated rate programs. At this
time, we cannot predict the outcome of this NOI.

Cash Management NOPR. In August 2002, the FERC issued a NOPR requiring
that all cash management or money pool arrangements between a FERC regulated
subsidiary and a non-FERC regulated parent must be in writing, and set forth:
the duties and responsibilities of cash management participants and
administrators; the methods of calculating interest and for allocating interest
income and expenses; and the restrictions on deposits or borrowings by money
pool members. The NOPR also requires specified documentation for all deposits
into, borrowings from, interest income from, and interest expenses related to,
these arrangements. Finally, the NOPR proposes that as a condition of
participating in a cash management or money pool arrangement, the FERC regulated
entity must maintain a minimum proprietary capital balance of 30 percent, and
the FERC regulated entity and its parent must maintain investment grade credit
ratings. In August 2002 comments were filed. The FERC held a public conference
in September 2002, to discuss the issues raised in the comments. Representatives
of companies from the gas and electric industries participated on a panel and
uniformly agreed that the proposed regulations should be revised substantially
and that the proposed capital balance and investment grade credit rating
requirements would be excessive. At this time, we cannot predict the outcome of
this NOPR.

Also in August 2002, FERC's Chief Accountant issued an Accounting Release,
which was effective immediately, providing guidance on how companies should
account for money pool arrangements and the types of documentation that should
be maintained for these arrangements. However, the Accounting Release did not
address the proposed requirements that the FERC regulated entity maintain a
minimum proprietary capital balance of 30 percent and that the entity and its
parent have investment grade credit ratings. Requests for rehearing were filed
in August 2002. The FERC has not yet acted on the rehearing requests.

If the cash management NOPR is adopted by the FERC, our HIOS and Petal
interstate facilities will no longer be permitted to participate in a money pool
or cash management program. As a result, more frequent distributions or equity
contributions may be needed in anticipation of monthly cash flow requirements
for those interstate facilities. Also, separate credit facilities and resources
may be required to support the capital and day-to-day activities for the
interstate facilities separate from other of our subsidiaries and our primary
bank accounts.

Emergency Reconstruction of Interstate Natural Gas Facilities NOPR. In
April 2002, FERC and the Department of Transportation, Office of Pipeline Safety
convened a technical conference to discuss how to clarify, expedite, and
streamline permitting and approvals for interstate pipeline reconstruction in
the event of disaster, whether natural or otherwise. In January 2003, FERC
issued a NOPR proposing to (1) expand the scope of construction activities
authorized under a pipeline's blanket certificate to allow replacement of
mainline facilities; (2) authorize a pipeline to commence reconstruction of the
affected system without a waiting period; and (3) authorize automatic approval
of construction that would be above the normal cost ceiling. Comments on the
NOPR were due on February 27, 2003. At this time we cannot predict the outcome
of this rulemaking.

Pipeline Safety Notice of Proposed Rulemaking. On January 28, 2003, the
U.S. Department of Transportation issued a NOPR proposing to establish a rule
requiring pipeline operators to develop integrity management programs to
comprehensively evaluate their pipelines, and take measures to protect pipeline
segments located in what the notice refers to as "high consequence areas." The
proposed rule resulted from

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the enactment of the Pipeline Safety Improvement Act of 2002, a new bill signed
into law in December 2002. We intend to submit comments on the NOPR, which are
due on March 31, 2003. At this time, we cannot predict the outcome of this
rulemaking.

Other Regulatory Matters. Our HIOS system is 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. 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 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.

In June 2002, Petal Gas Storage, which is also subject to the FERC's
jurisdiction filed with the FERC a certificate application to add additional gas
storage capacity to Petal's storage system. The filing included a new storage
cavern with a working gas 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 3 Bcf and related surface facilities, natural gas, water and
brine transmission lines. In February 2003, the FERC approved the facilities
proposed by Petal.

In December 1999, EPGT Texas filed a petition with the FERC for approval of
its 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 service. FERC also 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 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. The requested market-based rates are
currently subject to refund. Falcon also intervened in this filing, complaining
that market-based rates should be denied because of their complaint about access
on the EPGT pipeline for third party imbalance services. We filed a response
stating that their complaint is not relevant to the rate case, that a severance
of this issue has been requested in the EPGT pipeline rate case, and requesting
a dismissal of their intervention. This matter is pending before the FERC.

While the outcome of all of our rates and regulatory matters cannot be
predicted with certainty, based on information known to date, we do not expect
the ultimate resolution of these matters will have a material adverse effect on
our financial position, results of operations or cash flows. As new information
becomes

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

available or relevant developments occur, we will review our accruals and make
any appropriate adjustments. The impact of these changes may have a material
effect on our results of operations.

Operating Lease

We have long-term operating lease commitments associated with the Wilson
natural gas storage facility we acquired in April 2002 in connection with the
EPN Holding acquisition. The term of the natural gas storage facility and base
gas leases runs through 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 future minimum lease payments under these operating lease commitments
as of December 31, 2002 are as follows (in thousands):

2003........................................................ $ 5,219
2004........................................................ 5,219
2005........................................................ 5,219
2006........................................................ 5,219
2007........................................................ 5,219
Remainder................................................... 2,609
-------
Total minimum lease payments................................ $28,704
=======

Rental expense under operating leases was approximately $3.9 million for
the year ended December 31, 2002. We did not have any operating leases prior to
our acquisition of the EPN Holding assets.

Guarantees

We conduct our business through our wholly-owned subsidiaries, joint
ventures and other ownership arrangements to construct, operate and finance the
development of our onshore and offshore midstream energy businesses. Third
parties routinely require us to provide performance and financial guarantees to
support the obligations of our subsidiaries under contracts entered into in
connection with our business. The events and circumstances that may require us,
on behalf of our subsidiaries, to perform under these guarantees include
nonperformance by our joint ventures and other affiliates of services, such as
gathering, transportation, processing and storage services, and nonpayment of
contractual obligations.

As of December 31, 2002, we had approximately $132.8 million of performance
guarantees in connection with the activities of our joint ventures and other
affiliates. Such contingent obligations are not recorded in our consolidated
financial statements unless they become payable. The most significant of our
performance guarantee commitments is related to the construction of the Marco
Polo TLP facility. We have guaranteed the payment of approximately $51 million
as of December 31, 2002, under the turnkey construction contract between
Deepwater Gateway and the construction contractor. We are obligated to perform
under this guarantee should Deepwater Gateway fail to satisfy its obligations by
drawing under its $155 million project finance loan or Deepwater Gateway's joint
venture partners fail to perform under their joint venture agreement. Our
commitment under this guarantee is scheduled to expire in 2003.

As discussed in Note 6, we are also obligated under an agreement with
certain lenders to make payments on behalf of Deepwater Gateway for all
distributions we or any of our subsidiaries receive up to $22.5 million, if
Deepwater Gateway defaults on its payment obligations under their project
finance loan. Neither we, nor any of our subsidiaries have received any
distributions from Deepwater Gateway as of December 31, 2002.

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Other Matters

As a result of current circumstances generally surrounding the energy
sector, the creditworthiness of several industry participants has been called
into question. As a result of these general circumstances, we have established
an internal group to monitor our exposure to and determine, as appropriate,
whether we should request prepayments, letters of credit or other collateral
from our counterparties.

11. ACCOUNTING FOR HEDGING ACTIVITIES

A majority of our commodity purchases and sales, which relate to purchases
and sales of natural gas associated with our EPIA pipeline and San Juan assets,
sales of liquids associated with our interest in the Indian Basin processing
plant and sales of oil and natural gas associated with our production
operations, are at spot market or forward market prices. We use futures, forward
contracts, and swaps to limit our exposure to fluctuations in the commodity
markets and allow for a fixed cash flow stream from these activities. On January
1, 2001, we adopted the provisions of SFAS No. 133, Accounting for Derivatives
and Hedging Activities. We did not have any derivative contracts in place at
December 31, 2000, and therefore, there was no transition adjustment recorded in
our financial statements. During 2002 and 2001, we entered into cash flow
hedges.

In August 2002, we entered into a derivative financial instrument to hedge
our exposure during 2003 to changes in natural gas prices relating to gathering
activities in the San Juan Basin in anticipation of our acquisition of the San
Juan assets. The derivative is a financial swap on 30,000 MMBtu per day whereby
we receive a fixed price of $3.525 per MMBtu and pay a floating price based on
the San Juan index. From August 2002 through our acquisition date, November 27,
2002, we accounted for this derivative under mark-to-market accounting since it
did not qualify for hedge accounting under SFAS 133. Through the acquisition
date, we recognized a $0.4 million gain in the margin of our Natural gas
pipelines and plants segment. Beginning with the acquisition date in November
2002, we are accounting for this derivative as a cash flow hedge under SFAS No.
133. As of December 31, 2002, the fair value of this cash flow hedge was a
liability of $4.8 million. No ineffectiveness exists in our hedging relationship
because all purchase and sale prices are based on the same index and volumes as
the hedge transaction. We estimate the entire amount will be reclassified from
accumulated other comprehensive income to earnings over the next 12 months. In
connection with our San Juan asset purchase, we also acquired the outstanding
risk management positions at the Chaco plant. The value of these NGL and natural
gas positions was a $0.5 million liability at the acquisition date and this
amount was included in the working capital adjustments to the purchase price.
These positions expired in December 2002.

At December 31, 2002, in connection with our EPIA operations, we have fixed
price contracts with specific customers for the sale of predetermined volumes of
natural gas for delivery over established periods of time. We entered into cash
flow hedges in 2001 and 2002 to offset the risk of increasing natural gas
prices. As of December 31, 2002, the fair value of these cash flow hedges was an
asset of approximately $86 thousand. For the twelve months ended December 31,
2002, the majority of these cash flow hedges expired and we reclassified a loss
of $1.4 million from accumulated other comprehensive income to earnings. We
estimate the entire amount will be reclassified from accumulated other
comprehensive income to earnings over the next six months. As of December 31,
2001, the fair value of these cash flow hedges was a liability of $1.3 million.
During the year ended December 31, 2001, we reclassified a gain of $400 thousand
from other comprehensive income to earnings. No ineffectiveness exists in our
hedging relationship because all purchase and sale prices are based on the same
index and volumes as the hedge transaction.

Beginning in April 2002, in connection with our EPN Holding acquisition, we
had swaps in place for our interest in the Indian Basin processing plant to
hedge the price received for the sale of natural gas liquids. All of these
hedges expired by December 31, 2002, and we recorded a loss of $163 thousand
during 2002 for these

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

cash flow hedges. We did not have any ineffectiveness in our hedging
relationship since all sale prices were based on the same index as the hedge
transaction.

In January 2002, Poseidon entered into a two-year interest rate swap
agreement to fix the variable LIBOR based interest rate on $75 million of its
$150 million variable rate revolving credit facility at 3.49% over the life of
the swap. Poseidon, under its credit facility, pays an additional 150 basis
points over the LIBOR rate resulting in an effective interest rate at 4.99% on
the hedged notional amount. As of December 31, 2002, the fair value of its
interest rate swap was a liability of $1.4 million resulting in accumulated
other comprehensive loss of $1.4 million. We included our 36 percent share of
this liability of $0.5 million as a reduction of our investment in Poseidon and
as loss in accumulated other comprehensive income which will be reclassified to
earnings proportionately over the next twelve months. Additionally, we have
recognized in income our 36 percent share of Poseidon's realized loss of $1.2
million for the twelve months ended December 31, 2002, or $0.4 million, through
our earnings from unconsolidated affiliates.

Our counterparties for EPIA and Indian Basin hedging activities are El Paso
Merchant Energy and El Paso Field Services, affiliates of our general partner.
We do not require collateral and do not anticipate non-performance by our
counterparties. The counterparty for Poseidon's hedging activity is Credit
Lyonnais. Poseidon does not require collateral and does not anticipate
non-performance by the counterparty. The counterparty of our San Juan hedging
activity is J. Aron and Company, a subsidiary of Goldman Sachs. We do not
require collateral and do not anticipate non-performance by the counterparty.

12. SUPPLEMENTAL DISCLOSURES TO THE STATEMENTS OF CASH FLOWS

Cash paid for interest, net of amounts capitalized were as follows:

Noncash investing and financing activities excluded from the statements of
cash flows were as follows:

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EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

13. MAJOR CUSTOMERS

The percentage of our revenue from major customers was as follows:

The 2002 percentage increase in revenue from El Paso Merchant Energy North
America Company and El Paso Field Services is primarily due to our EPN Holding
and San Juan asset acquisitions completed in 2002. The 2001 percentage declines
in revenue from some of our major customers in 2000 is primarily attributed to
increased revenue from our 2001 operations as a result of acquisitions in 2001,
principally the acquisition of the EPN Texas assets and Chaco.

14. BUSINESS SEGMENT INFORMATION:

Each of our segments are business units that offer different services and
products that are managed separately since each segment requires different
technology and marketing strategies. We have revised and renamed our business
segments to reflect changes in the composition of our operations as discussed
below. As a result 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.

As a result of our acquisition of EPN Texas in February 2001, we began
providing NGL transportation and fractionation services and have shown these
activities as a separate segment called Oil and NGL logistics. This segment also
includes the liquid transportation services of the Allegheny and Poseidon oil
pipelines which were previously reflected in the Natural gas pipelines and
plants segment and our Chaco cryogenic gas processing plant, which we acquired
in October 2001.

With the July 2001 installation of the Prince TLP facility in the Prince
Field, we began managing our platform operations separately from our gathering
and transportation operations. Accordingly, we have shown our platforms as a
separate segment called Platform services. This segment includes the East
Cameron 373, Viosca Knoll 817, Garden Banks 72, and Ship Shoal 331 and 332
platforms which were previously reflected in the Natural gas pipelines and
plants segment.

As a result of our agreement to sell the Prince TLP and our 9 percent
overriding royalty interest in the Prince Field to El Paso Corporation in
February 2002, the results of operations from these assets are reflected as
discontinued operations in our statements of income for all periods presented
and are not reflected in our segment results below; nor are the related assets
held for sale included in segment assets. The operations of our oil and natural
gas production activities are reflected in Other. Additionally, when we acquired
the Chaco processing plant in October 2001 we reflected the operations of this
asset in our Oil and NGL logistics segment. In light of the expectations of
acquiring additional natural gas pipeline and processing assets, effective
January 1, 2002, we moved the Chaco processing plant to our Natural gas
pipelines and plants segment.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

We have restated the prior periods, to the extent practicable, in order to
conform to the current business segment presentation. The results of operations
for the restated periods are not necessarily indicative of the results that
would have been achieved had the revised business structure been in effect
during the period.

The accounting policies of the individual segments are the same as those
described in Note 1. We record intersegment revenues at rates that approximate
market. Since earnings from unconsolidated affiliates can be a significant
component of earnings in several of our segments, we have chosen to evaluate
segment operating performance based on earnings before interest and income taxes
(EBIT) instead of operating income. We define EBIT as operating income, adjusted
for several items, including: earnings from unconsolidated affiliates, minority
interest of consolidated subsidiaries, gains and losses on sales of assets and
other miscellaneous non-operating items. Items that are not included in this
measure are financing costs, including interest and debt expense, income tax
benefit and discontinued operations. We believe this measurement is useful to
our investors because it allows them to evaluate the effectiveness of our
business and operations and our investments from an operational perspective,
exclusive of the costs to finance those activities and exclusive of income
taxes, neither of which are directly relevant to the efficiency of those
operations. This measurement may not be comparable to measurements used by other
companies and should not be used as a substitute for net income or other
performance measures such as operating cash flow.

In addition to EBIT, we also measure segment performance using performance
cash flows, or an asset's ability to generate cash flow. We believe our
presentation of performance cash flows provides additional information which may
be used to determine our ability to pay distributions, service our debt
obligations, and grow the business. Our management uses performance cash flows,
in addition to other information, to evaluate the performance of our assets,
determine how resources will be allocated, and develop strategic plans. These
measures are used as a supplemental financial measurement in the evaluation of
our business and should not be considered as an alternative to GAAP measures as
indicators of our operating performance or as measures of our liquidity.
Performance cash flows may not be a comparable measurement among different
companies.

Our operating results and financial position reflect the acquisitions of
the San Juan assets in November 2002, the EPN Holding assets in April 2002, the
Chaco plant and the remaining 50 percent interest we did not already own in
Deepwater Holdings in October 2001, EPN Texas in February 2001, the Petal and
Hattiesburg natural gas storage facilities in August 2000 and EPIA in March
2000. The acquisitions were accounted for as

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EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

purchases and therefore operating results of these acquired entities are
included prospectively from the purchase date. The following are results as of
and for the periods ended December 31:

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

(1) We finance our activities at the consolidated level and therefore we do not
allocate interest and debt expense among our segments.

(2) Performance cash flows is determined by taking earnings before interest and
income taxes and adding or subtracting, as appropriate, cash distributions
from unconsolidated affiliates; depreciation, depletion and amortization;
earnings from unconsolidated affiliates; gains and losses on asset sales;
and other nonrecurring items.

15. GUARANTOR FINANCIAL INFORMATION

In May 2001, we purchased our general partner's 1.01 percent non-managing
interest owned in twelve of our subsidiaries for $8 million. As a result of this
acquisition, all our subsidiaries, but not our equity investees, are wholly
owned by us. As of December 31, 2002, our revolving credit facility, EPN Holding
term credit facility, senior secured term loan and senior secured acquisition
term loan are guaranteed by each of our subsidiaries, excluding our unrestricted
subsidiaries, and are collateralized by our general and administrative services
agreement, substantially all of our assets, and our general partner's one
percent general partner interest. In addition, as of December 31, 2002, all of
our senior subordinated notes are jointly, severably, fully and unconditionally
guaranteed by us and all our subsidiaries excluding our unrestricted
subsidiaries. As of December 31, 2001, our revolving credit facility was
guaranteed by us and each of our subsidiaries (excluding Argo, L.L.C. and Argo
I, L.L.C. subsidiaries) and was collateralized by our general and administrative
services agreement, substantially all of our assets, and our general partner's
one percent general partner interest. In addition, all of our senior
subordinated notes were guaranteed by all of our subsidiaries except Argo and
Argo I. The consolidating eliminations column on our balance sheets eliminate
our investment in consolidating subsidiaries, intercompany payables and
receivables and other transactions between subsidiaries.

Non-guarantor subsidiaries for the year ended December 31, 2002, consisted
of Argo and Argo I for the quarter ended March 31, 2002, our EPN Holding
subsidiaries for the quarters ended June 30, 2002 and September 30, 2002, and
our unrestricted subsidiaries for the quarter ended December 31, 2002.
Non-guarantor subsidiaries for all other periods consisted of Argo and Argo I
which owned the Prince TLP. As a result of our disposal of the Prince TLP and
our related overriding royalty interest in April 2002, the results of operations
and net book value of these assets are reflected as discontinued operations in
our statements of income and assets held for sale in our balance sheets and Argo
and Argo I became guarantor subsidiaries.

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EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 2002

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

(1) Non-guarantor subsidiaries consisted of Argo and Argo I for the quarter
ended March 31, 2002; EPN Holding subsidiaries for the quarters ended June
30, 2002 and September 30, 2002; and our unrestricted subsidiaries for the
quarter ended December 31, 2002.

138

EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 2001

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

(1) Non-guarantor subsidiaries consist of Argo and Argo I, which were formed in
August 2000.

139

EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 2000

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

(1) Non-guarantor subsidiaries consist of Argo and Argo I, which were formed in
August 2000.

140

EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING BALANCE SHEETS
DECEMBER 31, 2002

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

(1) Non-guarantor subsidiaries consisted of Argo and Argo I for the quarter
ended March 31, 2002; EPN Holding subsidiaries for the quarters ended June
30, 2002 and September 30, 2002; and our unrestricted subsidiaries for the
quarter ended December 31, 2002.

141

EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING BALANCE SHEET
DECEMBER 31, 2001

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

(1) Non-guarantor subsidiaries consist of Argo and Argo I, which were formed in
August 2000.

142

EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
YEAR ENDED DECEMBER 31, 2002

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

(1) Non-guarantor subsidiaries consisted of Argo and Argo I for the quarter
ended March 31, 2002; EPN Holding subsidiaries for the quarters ended June
30, 2002 and September 30, 2002; and our unrestricted subsidiaries for the
quarter ended December 31, 2002.

143

EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW
YEAR ENDED DECEMBER 31, 2001

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

(1) Non-guarantor subsidiaries consist of Argo and Argo I, which were formed in
August 2000.

144

EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW
YEAR ENDED DECEMBER 31, 2000

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

(1) Non-guarantor subsidiaries consist of Argo and Argo I, which were formed in
August 2000.

145

EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

16. SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED):

General

This footnote discusses our oil and natural gas production activities for
the years 2001 and 2000. The year 2002 is not presented since these operations
are not a significant part of our business as defined by SFAS No. 69,
Disclosures About Oil and Gas Producing Activities, and we do not expect it to
become significant in the future.

Oil and Natural Gas Reserves

The following table represents our net interest in estimated quantities of
proved developed and proved undeveloped reserves of crude oil, condensate and
natural gas and changes in such quantities at year end 2001 and 2000. Estimates
of our reserves at December 31, 2001 and 2000, have been made by the independent
engineering consulting firm, Netherland, Sewell & Associates, Inc. except for
the Prince Field for 2001, which was prepared by El Paso Production Company, our
affiliate and operator of the Prince Field. Net proved reserves are the
estimated quantities of crude oil and natural gas which geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions. Our policy is to recognize proved reserves only when economic
producibility is supported by actual production. As a result, no proved reserves
were booked with respect to any of our producing fields in the absence of actual
production. Proved developed reserves are proved reserve volumes that can be
expected to be recovered through existing wells with existing equipment and
operating methods. Proved undeveloped reserves are proved reserve volumes that
are expected to be recovered from new wells on undrilled acreage or from
existing wells where a significant expenditure is required for recompletion.
Reference Rules 4-10(a)(2)(i), (ii), (iii), (3) and (4) of Regulation S-X, for
detailed definitions of proved reserves, which can be found at the SEC's
website, http://www.sec.gov/divisions/corpfin/forms/ regsx.htm#gas.

Estimates of reserve quantities are based on sound geological and
engineering principles, but, by their very nature, are still estimates that are
subject to substantial upward or downward revision as additional information
regarding producing fields and technology becomes available.

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

(1) Includes our overriding royalty interest in proved reserves on Garden Banks
Block 73 and the Prince Field.

(2) Includes our overriding royalty interest in proved reserves of 1,341 MBbls
of oil and 1,659 MMcf of natural gas on our Prince Field, which began
production in 2001. These reserves were not included in proved reserves
prior to 2001 because, consistent with our policy, economic producibility
had not been supported by actual production. Also, we had increases in
estimated proved reserves relating to our producing properties, primarily at
our West Delta 35 field. Actual production in the Prince Field for 2001 was
37 MBbls of oil and 32 MMcf of natural gas.

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EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following are estimates of our total proved developed and proved
undeveloped reserves of oil and natural gas by producing property as of December
31, 2001.

In general, estimates of economically recoverable oil and natural gas
reserves and of the future net revenue therefrom are based upon a number of
variable factors and assumptions, such as historical production from the subject
properties, the assumed effects of regulation by governmental agencies and
assumptions concerning future oil and natural gas prices, future operating costs
and future plugging and abandonment costs, all of which may vary considerably
from actual results. All such estimates are to some degree speculative, and
classifications of reserves are only attempts to define the degree of
speculation involved. For these reasons, estimates of the economically
recoverable oil and natural gas reserves attributable to any particular group of
properties, classifications of such reserves based on risk of recovery and
estimates of the future net revenue expected therefrom, prepared by different
engineers or by the same engineers at different times, may vary substantially.
The meaningfulness of such estimates is highly dependent upon the assumptions
upon which they are based.

Estimates with respect to proved undeveloped reserves that may be developed
and produced in the future are often based upon volumetric calculations and upon
analogy to similar types of reserves rather than upon actual production history.
Estimates based on these methods are generally less reliable than those based on
actual production history. Subsequent evaluation of the same reserves based upon
production history will result in variations, which may be substantial, in the
estimated reserves. A significant portion of our reserves is based upon
volumetric calculations.

Future Net Cash Flows

The standardized measure of discounted future net cash flows relating to
our proved oil and natural gas reserves is calculated and presented in
accordance with SFAS No. 69. Accordingly, future cash inflows were determined by
applying year-end oil and natural gas prices, as adjusted for fixed price
contracts in effect, to our estimated share of future production from proved oil
and natural gas reserves. The average prices utilized in the calculation of the
standardized measure of discounted future net cash flows at December 31, 2001,
were $16.75 per barrel of oil and $2.62 per Mcf of natural gas. Actual future
prices and costs may be materially higher or lower. Future production and
development costs were computed by applying year-end costs to future years. As
we are not a taxable entity, no future income taxes were provided. A prescribed
10 percent discount factor was applied to the future net cash flows.

In our opinion, this standardized measure is not a representative measure
of fair market value, and the standardized measure presented for our proved oil
and natural gas reserves is not representative of the reserve value. The
standardized measure is intended only to assist financial statement users in
making comparisons between companies. In the table following, the amounts of
future production costs have been restated to

147

EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

include platform access fees paid to our platform segment. See note 2 to the
table for further discussion of the impact of such fees on our consolidated
standardized measure of discounted future net cash flows.

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

(1) Our future cash inflows include estimated future receipts from our
overriding royalty interest in our Prince Field and Garden Banks Block 73.
Since these are overriding royalty interests, we do not participate in the
production or development costs for these fields, but do include their
proved reserves, production volumes and future cash inflows in our data.

(2) Our future production costs include platform access fees paid by our oil and
natural gas production business to affiliated entities included in our
platforms segment. Such platform access fees are eliminated in our
consolidated financial statements. The future platform access fees paid to
our platform segment were $4,960 for 2001 and $13,080 for 2000. On a
consolidated basis, our standardized measure of discounted future net cash
flows was $43,789 for 2001 and $89,749 for 2000.

Estimated future net cash flows for proved developed and proved undeveloped
reserves as of December 31, 2001, are as follows:

The following are the principal sources of change in the standardized
measure:

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EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Development, Exploration, and Acquisition Expenditures

The following table details certain information regarding costs incurred in
our development, exploration, and acquisition activities during the years ended
December 31:

In each of the years presented, we elected not to incur any costs to
develop our proved undeveloped reserves. However, we expect to incur
approximately $2.6 million within the next three years to develop these
reserves.

Capitalized Costs

Capitalized costs relating to our natural gas and oil producing activities
and related accumulated depreciation, depletion and amortization were as follows
as of December 31:

149

EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Results of operations

Results of operations from producing activities by fiscal year were as
follows at December 31:

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

(1) These production costs include platform access fees paid to affiliated
entities included in our platform segment. Such platform access fees, which
were approximately $10 million in each of the years presented, are
eliminated in our consolidated financial statements.

17. SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION:

150

EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

151

REPORT OF INDEPENDENT ACCOUNTANTS

To the Unitholders of El Paso Energy Partners, L.P.
and the Board of Directors and Stockholder of
El Paso Energy Partners Company, as General Partner:

In our opinion, the consolidated financial statements listed in the index
appearing under Item 15(a)1. on page 163 present fairly, in all material
respects, the financial position of El Paso Energy Partners, L.P. and its
subsidiaries (the "Partnership") at December 31, 2002 and 2001, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2002 in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion,
the financial statement schedule listed in the index appearing under Item 15(a)2
presents fairly, in all material respects, the information set forth therein
when read in conjunction with the related consolidated financial statements.
These financial statements and the financial statement schedule are the
responsibility of the Partnership's management; our responsibility is to express
an opinion on these financial statements and the financial statement schedule
based on our audits. We conducted our audits of these statements in accordance
with auditing standards generally accepted in the United States of America,
which require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, the
Partnership changed its method of accounting for the impairment and disposal of
long lived assets effective January 1, 2002.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
March 24, 2003

152

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

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

GENERAL

We and our general partner utilize the employees of and management services
provided by El Paso Corporation and its affiliates under our general and
administrative agreement. We reimburse our general partner and its affiliates
for reasonable general and administrative expenses, and other reasonable
expenses, incurred by them.

As a result of recent clarifications in the insider trading rules, and in
particular, the promulgation of Rule 10b5-1, we have revised our insider trading
policy to allow certain officers and directors to establish pre-established
trading plans. Rule 10b5-1 allows certain officers and directors to establish
written programs that permit an independent person who is not aware of insider
information at the time of the trade to execute pre-established trades of our
securities for the officer or directors according to fixed parameters. As of
March 6, 2003, no officer or director has established a trading plan. However,
we intend to disclose the existence of any trading plan in compliance with Rule
10b5-1 in future filings with the Securities and Exchange Commission (SEC).

GOVERNANCE MATTERS

We are committed to sound principles of governance. Such principles are
critical for us to achieve our performance goals, and to maintain the trust and
confidence of investors, employees, suppliers, business partners and other
stakeholders. The following is a brief discussion of certain existing practices
and recent developments that we have undertaken to maintain strong governance
principles.

Independence of Board Members. A key element for strong governance is
independent members of the board of directors. Our general partner is committed
to having at least a majority of its Board of Directors be comprised of
independent directors. Pursuant to rules proposed by the New York Stock Exchange
(NYSE), a director will be considered independent if the board determines that
he or she does not have a material relationship with our general partner or us
(either directly or as a partner, shareholder or officer of an organization that
has a material relationship with our general partner or us). Based on the
foregoing, the Board has affirmatively determined that Michael B. Bracy, H.
Douglas Church and Kenneth L. Smalley are "independent" under the rules proposed
by the NYSE. Thus, the Board of Directors of our general partner has a majority
(60 percent) of independent directors.

Heightened Independence for Audit and Conflicts Committee Members. As
required by the Sarbanes-Oxley Act of 2002, the SEC recently proposed rules that
would direct national securities exchanges and associations to prohibit the
listing of securities of a public company if members of its audit committee did
not satisfy a heightened independence standard. In order to meet this standard,
a member of an audit committee may not receive any consulting fee, advisory fee
or other compensation from the public company other than fees for service as a
director or committee member, and may not be considered an affiliate of the
public company. Based on the foregoing criteria, the Board of Directors of our
general partner has affirmatively determined that all members of the Audit and
Conflicts Committee satisfy this heightened independence requirement.

Audit Committee Financial Expert. An audit committee plays an important
role in promoting effective corporate governance, and it is imperative that
members of an audit committee have requisite financial literacy and expertise.
All members of the Audit and Conflicts Committee meet the financial literacy
required by the NYSE rules. In addition, as required by the Sarbanes-Oxley Act
of 2002, the SEC recently adopted rules requiring that public companies disclose
whether or not its audit committee has an "audit committee
153

financial expert" as a member. An "audit committee financial expert" is defined
as a person who, based on his or her experience, satisfies all of the following
attributes:

- An understanding of generally accepted accounting principles and
financial statements.

- An ability to assess the general application of such principles in
connection with the accounting for estimates, accruals, and reserves.

- Experience preparing, auditing, analyzing or evaluating financial
statements that present a breadth and level of complexity of accounting
issues that are generally comparable to the breadth and level of
complexity of issues that can reasonably be expected to be raised by El
Paso Energy Partners' financial statements, or experience actively
supervising one or more persons engaged in such activities.

- An understanding of internal controls and procedures for financial
reporting.

- An understanding of audit committee functions.

Based on the information presented, the Board of Directors has affirmatively
determined that Michael B. Bracy satisfies the definition of "audit committee
financial expert."

Executive Sessions of Board. The Board of Directors of our general partner
will hold regular executive sessions in which non-management board members meet
without any members of management present. The purpose of these executive
sessions is to promote open and candid discussion among the non-management
directors. During such executive sessions, there shall be one director
designated as the "Presiding Director," who shall be responsible for leading and
facilitating such executive sessions. Initially, for 2003, the Presiding
Director shall be the Chairman of the Audit and Conflicts Committee. Each
calendar year the position of Presiding Director shall rotate among the
committee chairs of the Audit and Conflicts Committee and the Governance and
Compensation Committee.

Committees of Board of Directors. In response to the Sarbanes-Oxley Act of
2002 and the rules proposed by the NYSE, the Board of Directors of our general
partner has made certain amendments to the charter of the Audit and Conflicts
Committee. In addition, the Board has established a new Compensation and
Governance Committee, the responsibilities of which are discussed below.

Governance Guidelines. Governance guidelines, together with committee
charters, provide the framework for the effective governance. The Board of
Directors of our general partner has adopted the El Paso Energy Partners
Governance Guidelines addressing several matters, including qualifications for
directors, responsibilities of directors, retirement of directors, the
composition and responsibility of committees, the conduct and frequency of board
and committee meetings, management succession, director access to management and
outside advisors, director compensation, director orientation and continuing
education, and annual self-evaluation of the board. The Board of Directors of
our general partner recognizes that effective governance is an on-going process,
and thus, the Board will review the El Paso Energy Partners Governance
Guidelines annually or more often as deemed necessary.

Web Access. We provide access through our website to current information
relating to governance, including a copy of each Board committee charter, the
Code of Business Conduct, the El Paso Energy Partners Governance Guidelines and
other matters impacting our governance principles. We also provide access
through our website to all filings submitted by El Paso Energy Partners with the
SEC. The company's website is www.elpasopartners.com and access to this
information is free of any charge to the user.

DIRECTORS AND EXECUTIVE OFFICERS OF OUR GENERAL PARTNER

The following table sets forth certain information as of March 6, 2003,
regarding the executive officers and directors of our general partner. Each
executive officer of our general partner serves us in the same office or offices
each such officer holds with our general partner. Directors are elected annually
by our general partner's sole stockholder, DeepTech International Inc., and hold
office until their successors are elected and qualified. Each executive officer
named in the following table has been elected to serve until his successor is
duly appointed or elected or until his earlier removal or resignation from
office.

154

On October 17, 2002, in order to move toward compliance with the New York
Stock Exchange's proposed corporate governance requirements, three former
directors of our general partner resigned. The resigning directors, who serve as
directors and/or officers of El Paso Corporation, would not have been considered
independent for purposes of the NYSE rules.

On January 28, 2003, the Board of Directors established a Governance and
Compensation Committee, determined that all three independent directors (Messrs.
Bracy, Church and Smalley), satisfy the independence requirements for audit
committee eligibility and determined that Messr. Bracy is an audit committee
financial expert as determined by the Securities and Exchange Commission rules.

There is no family relationship among any of the executive officers or
directors of our general partner, and, other than described herein, no
arrangement or understanding exists between any executive officer and any other
person pursuant to which he was or is to be selected as an officer.

Mr. Phillips has served as a Director of our general partner since August
1998. He has served as Chief Executive Officer for us and our general partner
since November 1999 and as Chairman since October 2002. He served as Executive
Vice President from August 1998 to October 1999. Mr. Phillips has served as
President of El Paso Field Services Company since June 1997. He served as
President of El Paso Energy Resources Company from December 1996 to June 1997,
President of El Paso Field Services Company from April 1996 to December 1996 and
Senior Vice President of El Paso from September 1995 to April 1996. For more
than five years prior, Mr. Phillips was Chief Executive Officer of Eastex
Energy, Inc.

Mr. Lytal has served as a Director of our general partner since August 1994
and as our President and the President of our general partner since July 1995.
He served as Senior Vice President for us and our general partner from August
1994 to June 1995. Prior to joining us, Mr. Lytal served in various capacities
in the oil and gas exploration and production and gas pipeline industries with
United Gas Pipeline Company, Texas Oil and Gas, Inc. and American Pipeline
Company.

Mr. Leland has served as Senior Vice President for us and our general
partner since July 2000 and as Chief Operating Officer for us and our general
partner since January 2003, and as Vice President of El Paso Field Services
Company since September 1997. He served as Senior Vice President and Controller
for us and our general partner from July 2000 through December 2002 and as Vice
President and Controller for us and our general partner from August 1998 to July
2000. He served as Director of Business Development for El Paso Field Services
Company from September 1994 to September 1997. For more than five years prior,
Mr. Leland served in various capacities in the finance and accounting functions
of El Paso Corporation.

Mr. Forman has served as Chief Financial Officer for us and our general
partner since January 1992 and served as a Director of our general partner from
July 1992 to August 1998. From 1982 to 1992, Mr. Forman served as Vice President
of the Natural Gas Pipeline Group of Manufacturers Hanover Trust Company.

Mr. Bracy has served as a Director of our general partner since October
1998 and is an audit committee financial expert as determined under the
Securities and Exchange Commission rules. From January 1993 to August 1997, Mr.
Bracy served as a Director, Executive Vice President and Chief Financial Officer
of NorAm Energy Corp. For nine years prior, Mr. Bracy served in various
executive capacities with NorAm. Mr. Bracy is a member of the Board of Directors
of Itron, Inc., which is not related to El Paso Energy Partners, L.P.

155

Mr. Church has served as a Director of our general partner since January
1999. From January 1994 to December 1998, Mr. Church served as the Senior Vice
President, Transmission, Engineering and Environmental for a subsidiary of Duke
Energy Corporation, Texas Eastern Transmission Company. For thirty-two years
prior, Mr. Church served in various engineering and operating capacities with
Texas Eastern Transmission Company, Panhandle Eastern Corporation and
Transwestern Pipeline Company. Mr. Church is a past member of the Board of
Directors of Southern Gas Association and is past Chairman of Boys and Girls
Country of Houston, Inc., which are not related to El Paso Energy Partners, L.P.

Mr. Smalley has served as a Director of our general partner since June
2001. Mr. Smalley has been retired since February 1992. For more than five years
prior to that date, Mr. Smalley was a Senior Vice President of Phillips
Petroleum Company and President of Phillips 66 Natural Gas Company, a Phillips
Petroleum Company subsidiary. Mr. Smalley served as a member of the Board of
Directors of El Paso Corporation from 1992 to 2001.

COMPENSATION OF DIRECTORS

Non-employee directors of our general partner are entitled to receive an
annual retainer fee of forty-thousand dollars, with the chairman of any board
committees entitled to receive an additional fifteen thousand dollars per year.
All directors of our general partner are entitled to reimbursement for their
reasonable out-of-pocket expenses in connection with their travel to and from,
and attendance at, meetings of the Board or Board committees thereof.

In August 1998, we adopted the Director Plan to provide our general partner
with the ability to issue unit options to attract and retain the services of
knowledgeable directors. Unit options and restricted units to purchase a maximum
of 100,000 of our common units may be issued pursuant to the Director Plan.
Under the Director Plan, each non-employee director receives a grant of 2,500
unit options upon initial election to the Board of Directors and an annual unit
option grant of 2,000 unit options and, beginning in 2001, an annual restricted
unit grant equal to the director's annual retainer (including Chairman's
retainers, if applicable) divided by the fair market value of the common units
on the grant date upon each re-election to the Board of Directors. Each unit
option that is granted will vest immediately at the date of grant and will
expire ten years from such date, but will be subject to earlier termination in
the event that such non-employee director ceases to be a director of our general
partner for any reason, in which case the unit options expire 36 months after
such date except in the case of death, in which case the unit options expire 12
months after such date. Each director receiving a grant of restricted units is
recorded as a unitholder of the general partner and has all the rights of a
unitholder with respect to such units, including the right to distributions on
those units. The restricted units are nontransferable during the director's
service on the Board of Directors. The restrictions on the restricted units will
end and the director will receive one common unit for each restricted unit
granted upon the director's termination. The Director Plan is administered by a
management committee consisting of the Chairman of the Board and such other
senior officers of our general partner or its affiliates as the Chairman of the
Board may designate.

In 1998, we granted 3,000 unit options to purchase an equal number of
common units with an average exercise price of $26.17 per unit; in 1999, we
granted 4,500 unit options to purchase an equal number of common units with an
average exercise price of $21.58 per unit; in 2000, we granted 3,000 unit
options to purchase an equal number of common units with an exercise price of
$25.5625 per unit; in 2001, we granted 11,000 unit options to purchase an equal
number of common units with an exercise price of $33.00 per unit and 4,090
restricted units; and in 2002, we granted 8,000 unit options to purchase an
equal number of common units with an exercise price of $32.13 per unit and 5,429
restricted units. At March 6, 2003, 63,481 units remain unissued under the
Director Plan.

AUDIT AND CONFLICTS COMMITTEE

The Audit and Conflicts Committee currently consists of Messrs. Bracy
(chairman), Church and Smalley, each a non-employee director, and each of whom
is "independent" (as such term is defined in the proposed amendments to the NYSE
listing standards, as more fully described above). With respect to the
156

Audit function, the Committee advises the Board of Directors on matters
regarding the system of internal controls and the annual audit by independent
accountants and reviews policies and practices of our general partner and us.
The Committee is responsible for the appointment, compensation, retention and
oversight of any accounting firm engaged for the purpose of preparing or issuing
an audit report or related work or performing other audit, review or attestation
services for the Partnership and for the resolution of any potential
disagreement between management and the Partnership's auditors regarding
financial reporting. The Partnership's independent auditor reports directly to
this Committee. With respect to the Conflicts function, the Committee, at the
request of our general partner, reviews specific matters as to which our general
partner believes there may be a conflict of interest in order to determine if
the resolution of such conflict proposed by our general partner is fair and
reasonable to us. The Committee evaluates, and where appropriate, negotiates
proposed transactions, engages independent financial advisors and independent
legal counsel to assist with its evaluation of the proposed transactions, and
determines whether to approve and recommend the proposed transactions. The
Charter of the Audit and Conflicts Committee is attached to this annual report
as Exhibit 99.C.

GOVERNANCE AND COMPENSATION COMMITTEE

The Governance and Compensation Committee was formed on January 28, 2003.
The Governance and Compensation currently consists of Messrs. Smalley
(chairman), Bracy and Church, each a non-employee director, and each of whom is
"independent" (as such term is defined in the proposed amendments to the NYSE
listing standards, as more fully described above). With respect to its
governance function, the Committee is responsible for developing and
recommending to the Board governance principles, reviewing the qualifications of
candidates for Board membership, screening possible candidates for Board
membership and communicating with directors regarding Board meeting format and
procedures. The Committee also has responsibility for annual performance
evaluations for the Board and each committee. With respect to its compensation
functions, the Committee is responsible for reviewing our executive compensation
strategy to ensure that management is rewarded appropriately for its
contributions to our growth and profitability and that the executive
compensation strategy supports organization objectives. In consultation with the
Compensation Committee of El Paso Corporation, the Committee shall review
annually and approve the individual elements of total compensation for the Chief
Executive Officer and other executive officers of the general partner and
prepare a report on the factors and criteria on which their compensation was
based. The Charter of the Compensation and Governance Committee is attached to
this annual report as Exhibit 99.D.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

During 2002, only employees of El Paso Corporation and its affiliates,
through our general partner, were the individuals who worked on our matters.
While compensation awarded to those individuals during 2002 was handled by El
Paso Corporation, the Governance and Compensation Committee is expected to
handle these matters going forward. The Governance and Compensation Committee
has neither interlocks nor insider participation.

COMPENSATION OF OUR GENERAL PARTNER

Our general partner receives no remuneration in connection with our
management other than: (i) distributions on its general and limited partner
interests in us; (ii) incentive distributions on its general partner interest,
as provided in the partnership agreement, and (iii) reimbursement for all direct
and indirect costs and expenses incurred, all selling, general and
administrative expenses incurred, and all other expenses necessary or
appropriate to the conduct of the business of, and allocable to, us, including,
but not limited to the management fees paid by our general partner to a
subsidiary of El Paso Corporation under its general and administrative services
agreement.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Our general partner's directors, officers and beneficial owners of more
than 10 percent of a registered class of our equity securities are required to
file reports of ownership and reports of changes in ownership with the
157

SEC and the NYSE. Directors, officers and beneficial owners of more than 10
percent of our equity securities are also required to furnish us with copies of
all such reports that are filed. Based on our review of copies of such forms and
amendments, except as set forth below, we believe directors, executive officers
and greater than 10 percent beneficial owners complied with all filing
requirements during the year ended December 31, 2002. In connection with our
November 2002 acquisition of the San Juan assets, El Paso Corporation and
certain of its subsidiaries, including our general partner, should have filed a
Form 4 reporting a change in beneficial ownership of our Series C units by
December 2, 2002. The appropriate form was filed on December 9, 2002. In
addition, two transactions related to our Series B Preference Units were
reported late in 2002. The first transaction should have been reported on a Form
4 by September 10, 2000, and the second transaction should have been reported on
a Form 4 by November 10, 2001. Both of these transactions were reported on
December 9, 2002.

ITEM 11. EXECUTIVE COMPENSATION

Our executive officers and the executive officers of our general partner
are compensated by El Paso Corporation and do not receive compensation from our
general partner or us for their services in such capacities with the exception
of awards pursuant to the Omnibus Plan discussed below. However, our general
partner does make payments to a subsidiary of El Paso Corporation pursuant to
its management agreement. See Item 10, Directors and Executive Officers of the
Registrant -- Compensation of Directors.

OMNIBUS PLAN

In August 1998, we adopted the Omnibus Plan to provide our general partner
with the ability to issue unit options to attract and retain the services of
knowledgeable officers and key management personnel. Unit options to purchase a
maximum of 3 million common units may be issued pursuant to the Omnibus Plan.
The Omnibus Plan is administered by our general partner's Board of Directors.
The Board of Directors shall interpret the Omnibus Plan, shall prescribe, amend
and rescind rules relating to it, select eligible participants, make grants to
participants who are not Section 16 insiders pursuant to the Securities Exchange
Act, and shall take all other actions necessary for the Omnibus Plan
administration, which actions shall be final and binding upon all the
participants.

In August 1998, we granted 930,000 unit options to employees of our general
partner to purchase an equal number of common units at $27.1875 per unit and in
2001, we granted 1,008,000 unit options to purchase an equal number of common
units at $34.99 per unit pursuant to the Omnibus Plan. No grants of unit options
were made in 1999, 2000 or 2002. At March 27, 2003, 1,134,500 unit options
remain unissued under the Omnibus Plan.

REPORT FROM COMPENSATION COMMITTEE REGARDING EXECUTIVE COMPENSATION

Because we did not have a compensation committee or another committee
performing similar functions during 2002, this report is presented by the full
Board of Directors of our general partner. We have formed a Governance and
Compensation Committee that will present these reports in the future. The Board
of Directors of our general partner was responsible for establishing appropriate
compensation goals for the knowledgeable officers and key management personnel
working for us and evaluating the performance of such officers and personnel in
meeting such goals.

The goals of the Board of Directors in administering compensation,
including the Omnibus Plan, are as follows:

(1) To fairly compensate the knowledgeable officers and key management
personnel working for us and our affiliates for their contributions to our
short-term and long-term performance.

(2) To allow us to attract, motivate and retain the management
personnel necessary to our success by providing an Omnibus Plan comparable
to that offered by companies with which we compete for management
personnel.

158

The elements of compensation, including of the Omnibus Plan, described
above are implemented and have been periodically reviewed and adjusted by the
Board of Directors. The awards made under the Omnibus Plan have been determined
based on individual performance, experience and comparison with awards made by
our industry peers and other companies in similar industries with comparable
revenue while linking such awards to our achievement of financial goals. Going
forward, the Governance and Compensation Committee, described above, will be
responsible for such compensation matters.

SUMMARY COMPENSATION TABLE

The following table sets forth information concerning the annual
compensation earned by our Chief Executive Officer and each of our other four
most highly compensated executive officers whose annual salary and bonus during
the year ended December 31, 2002, exceeded $100,000:

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

(1) Other than awards made under our incentive arrangements, all other
compensation was paid by El Paso Corporation or subsidiaries of El Paso
Corporation.

UNIT OPTION GRANTS

No unit options were granted to the named executives during 2002.

UNIT OPTION EXERCISES AND YEAR-END VALUE TABLE

The following table sets forth information concerning unit option exercises
and the fiscal year-end values of the unexercised unit options, provided on an
aggregate basis, for each of the executives named in this Form 10-K.

AGGREGATED UNIT OPTION EXERCISES IN 2002
AND FISCAL YEAR-END UNIT OPTION VALUES

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

(1)The figures presented in these columns have been calculated based upon the
difference between $27.675, the fair market value of the common units on
December 31, 2002, for each in-the-money unit option, and its exercise price.
No cash is realized until the units received upon exercise of an option are
sold. No stock appreciation rights were outstanding on December 31, 2002.

159

ITEM 12. SECURITY OWNERSHIP OF MANAGEMENT

The following table sets forth, as of March 6, 2003, the beneficial
ownership of the outstanding equity securities of us, by (i) each person who is
known to us to beneficially own more than 5 percent of our outstanding units,
(ii) each director of our general partner and (iii) all directors and executive
officers of our General Partner as a group.

- ---------------
* Less than 1 percent.
(1) The Directors and executive Officers have the right to acquire common units
reflected in this column within 60 days of March 6, 2003, through the
exercise of unit options.
(2) The address for our general partner and El Paso Corporation is El Paso
Building, 1001 Louisiana Street, Houston, Texas 77002. All of our general
partner's outstanding common stock, par value $0.10 per share, is indirectly
owned by El Paso Corporation. Our general partner has no other class of
capital stock outstanding. El Paso Corporation, through its subsidiaries,
owned 11,674,245 common units, or 26.5 percent of our outstanding common
units, 10,937,500 Series C units (each of which can be converted into one
common unit after an affirmative vote of the common unitholders), 125,392
Series B preference units and our 1 percent general partner interest.
(3) The amount reflected for Mr. Lytal excludes 34 common units owned by his
son, a minor.
(4) Some common units reflected in this column for certain individuals are
subject to restrictions.

EQUITY COMPENSATION PLAN INFORMATION
AS OF DECEMBER 31, 2002

- ---------------
(1) Included in the equity compensation plans not approved by common unitholders
are the El Paso Energy Partners, L.P. 1998 Omnibus Compensation Plan and
1998 Unit Option Plan for Non-Employee Directors. These plans are described
in Item 8, Financial Statements and Supplementary Data, Note 8.

160

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Historically, we have entered into transactions with El Paso Corporation
and its subsidiaries to acquire or sell assets. We have instituted specific
procedures for evaluating and valuing our material transactions with El Paso
Corporation and its subsidiaries. Before we consider entering into a transaction
with El Paso Corporation or any of its subsidiaries, we determine whether the
proposed transaction (i) would comply with the requirements under our indentures
and credit agreements, (ii) would comply with substantive law, and (iii) would
be fair to us and our limited partners. In addition, our general partner's board
of directors utilizes a Audit and Conflicts Committee comprised solely of
independent directors. This committee:

- evaluates and, where appropriate, negotiates the proposed transaction;

- engages an independent financial advisor and independent legal counsel to
assist with its evaluation of the proposed transaction; and

- determines whether to reject or approve and recommend the proposed
transaction.

We will only consummate any proposed material acquisition or disposition with El
Paso Corporation if, following our evaluation of the transaction, the Audit and
Conflicts Committee approves and recommends the proposed transaction and our
full Board approves the transaction.

We and El Paso Corporation and its subsidiaries share the time and effort
of general partner personnel who provide services to us, including directors,
officers and other personnel. These shared personnel include officers and
directors who function as both our representatives and those of El Paso
Corporation and its subsidiaries. Some of these shared officers and directors
own and are awarded from time to time shares, or options to purchase shares, of
El Paso Corporation; accordingly, their financial interests may not always be
aligned completely with ours.

A discussion of certain agreements, arrangements and transactions between
or among us, our general partner, El Paso Corporation and its subsidiaries and
certain other related parties is summarized in Part II, Item 8, Financial
Statements and Supplementary Data, Notes 2 and 9. Also see Item 10, Directors
and Executive Officers of the Registrant.

ITEM 14. CONTROLS AND PROCEDURES

Evaluation of Controls and Procedures. Under the supervision and with the
participation of management, including our principal executive officer and
principal financial officer, we have evaluated the effectiveness of the design
and operation of our disclosure controls and procedures (Disclosure Controls)
and internal controls (Internal Controls) within 90 days of the filing date of
this annual report pursuant to Rules 13a-15 and 15d-15 under the Securities
Exchange Act of 1934 (Exchange Act).

Definition of Disclosure Controls and Internal Controls. Disclosure
Controls are our controls and other procedures that are designed to ensure that
information required to be disclosed by us in the reports that we file or submit
under the Exchange Act is recorded, processed, summarized and reported, within
the time periods specified under the Exchange Act. Disclosure Controls include,
without limitation, controls and procedures designed to ensure that information
required to be disclosed by us in the reports that we file under the Exchange
Act is accumulated and communicated to our management, including our principal
executive officer and principal financial officer, as appropriate to allow
timely decisions regarding required disclosure. Internal Controls are procedures
which are designed with the objective of providing reasonable assurance that (1)
our transactions are properly authorized; (2) our assets are safeguarded against
unauthorized or improper use; and (3) our transactions are properly recorded and
reported, all to permit the preparation of our financial statements in
conformity with generally accepted accounting principles.

Limitations on the Effectiveness of Controls. Our management, including
the principal executive officer and principal financial officer, does not expect
that our Disclosure Controls and Internal Controls will prevent all errors and
all fraud. A control system, no matter how well conceived and operated, can
provide only reasonable, not absolute, assurance that the objectives of the
control system are met. Further, the design of a control system must reflect the
fact that there are resource constraints, and the benefits of controls must be
161

considered relative to their costs. Because of the inherent limitations in all
control systems, no evaluation of controls can provide absolute assurance that
all control issues and instances of fraud, if any, within the company have been
detected. These inherent limitations include the realities that judgments in
decision-making can be faulty, and that breakdowns can occur because of simple
errors or mistakes. Additionally, controls can be circumvented by the individual
acts of some persons, by collusion of two or more people, or by management
override of the controls. The design of any system of controls also is based in
part upon certain assumptions about the likelihood of future events, and there
can be no assurance that any design will succeed in achieving its stated goals
under all potential future conditions; over time, control may become inadequate
because of changes in conditions, or the degree of compliance with the policies
or procedures may deteriorate. Because of the inherent limitations in a
cost-effective control system, misstatements due to error or fraud may occur and
not be detected.

No Significant Changes in Internal Controls. We have sought to determine
whether there were any "significant deficiencies" or "material weaknesses" in El
Paso Energy Partners' Internal Controls, or whether El Paso Energy Partners had
identified any acts of fraud involving personnel who have a significant role in
El Paso Energy Partners' Internal Controls. This information was important both
for the controls evaluation generally and because the principal executive
officer and principal financial officer are required to disclose that
information to our Board's Audit Committee and our independent auditors and to
report on related matters in this section of the Annual Report. The principal
executive officer and principal financial officer note that, from the date of
the controls evaluation to the date of this Annual Report, there have been no
significant changes in Internal Controls or in other factors that could
significantly affect Internal Controls, including any corrective actions with
regard to significant deficiencies and material weaknesses.

Effectiveness of Disclosure Controls. Based on the controls evaluation,
our principal executive officer and principal financial officer have concluded
that, subject to the limitations discussed above, the Disclosure Controls are
effective to ensure that material information relating to El Paso Energy
Partners and its consolidated subsidiaries is made known to management,
including the principal executive officer and principal financial officer,
particularly during the period when our periodic reports are being prepared.

Officer Certifications. The certifications from the principal executive
officer and principal financial officer required under Sections 302 and 906 of
the Sarbanes-Oxley Act of 2002 have been included herein, or as Exhibits to this
Annual Report, as appropriate.

162

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) THE FOLLOWING DOCUMENTS ARE FILED AS PART OF THIS ANNUAL REPORT:

1. Financial Statements

Our consolidated financial statements are included in Part II, Item 8 of
this report:

The following financial statements of our equity investment is included on
the following pages of this report:

2. Financial statement schedules and supplementary
information required to be
submitted.

Schedule II -- Valuation and qualifying accounts --....
180

Schedules other than that listed above are omitted because
the information is not required, is not material or is
otherwise included in the consolidated financial statements
or notes thereto included elsewhere in this
Annual Report.

3. Exhibit list.......................................... 181

163

POSEIDON OIL PIPELINE COMPANY, L.L.C.

FINANCIAL STATEMENTS
WITH REPORTS OF INDEPENDENT ACCOUNTANTS
AS OF DECEMBER 31, 2002 AND 2001 AND FOR THE THREE YEARS IN THE PERIOD ENDED
DECEMBER 31, 2002

164

REPORT OF INDEPENDENT ACCOUNTANTS

To the Members of Poseidon Oil Pipeline Company, L.L.C.:

In our opinion, the accompanying balance sheets and the related statements
of income, members' capital, comprehensive income and changes in accumulated
other comprehensive income and cash flows present fairly, in all material
respects, the financial position of Poseidon Oil Pipeline Company, L.L.C. (the
"Company") at December 31, 2002 and 2001, and the results of its operations and
its cash flows for each of the two years in the period ended December 31, 2002,
in conformity with accounting principles generally accepted in the United States
of America. These financial statements are the responsibility of the Company's
management; our responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these statements in
accordance with auditing standards generally accepted in the United States of
America, which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion. The financial statements of
the Company as of December 31, 2000 and for the year then ended were audited by
other independent accountants who have ceased operations. Those independent
accountants expressed an unqualified opinion on those financial statements in
their report dated March 16, 2001.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
March 24, 2003

165

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Members of
Poseidon Oil Pipeline Company, L.L.C.:

We have audited the accompanying balance sheet of Poseidon Oil Pipeline Company,
L.L.C. (a Delaware limited liability company), as of December 31, 2000, and the
related statements of income, members' equity and cash flows for the years ended
December 31, 2000 and 1999. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Poseidon Oil Pipeline Company,
L.L.C., as of December 31, 2000, and the results of its operations and its cash
flows for the years ended December 31, 2000 and 1999, in conformity with
accounting principles generally accepted in the United States.

/s/ ARTHUR ANDERSEN LLP

Houston, Texas
March 16, 2001

THIS REPORT IS A COPY OF A PREVIOUSLY ISSUED REPORT AND THIS REPORT HAS NOT BEEN
REISSUED BY ARTHUR ANDERSEN LLP. THE REFERENCED 1999 FINANCIAL STATEMENTS ARE
NOT INCLUDED IN THE FINANCIAL STATEMENTS AS OF AND FOR THE YEAR ENDED DECEMBER
31, 2002.

166

POSEIDON OIL PIPELINE COMPANY, L.L.C.

STATEMENTS OF INCOME
(IN THOUSANDS)

See accompanying notes.
167

POSEIDON OIL PIPELINE COMPANY, L.L.C.

BALANCE SHEETS
AS OF DECEMBER 31, 2002 AND 2001
(IN THOUSANDS)

See accompanying notes.
168

POSEIDON OIL PIPELINE COMPANY, L.L.C.

STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

See accompanying notes.
169

POSEIDON OIL PIPELINE COMPANY, L.L.C.

STATEMENTS OF MEMBERS' CAPITAL
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(IN THOUSANDS)

See accompanying notes.
170

POSEIDON OIL PIPELINE COMPANY, L.L.C.

STATEMENTS OF COMPREHENSIVE INCOME AND
CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
(IN THOUSANDS)

See accompanying notes.
171

POSEIDON OIL PIPELINE COMPANY, L.L.C.

NOTES TO FINANCIAL STATEMENTS

NOTE 1 -- ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

Poseidon Oil Pipeline Company, L.L.C. is a Delaware limited liability
company, formed in February 1996, to design, construct, own and operate the
unregulated Poseidon Pipeline extending from the Gulf of Mexico to onshore
Louisiana.

Our members are Shell Oil Products U.S. (Shell) (formerly Equilon
Enterprises, L.L.C.), Poseidon Pipeline Company, L.L.C. (Poseidon), a subsidiary
of El Paso Energy Partners, L.P., and Marathon Pipeline Company (Marathon),
which own 36 percent, 36 percent, and 28 percent in us.

Shell was our operator from January 1, 1998 to December 31, 2000. Effective
January 1, 2001, Manta Ray Gathering Company, L.L.C., a subsidiary of El Paso
Energy Partners and an affiliate of ours became our operator.

We are in the business of transporting crude oil in the Gulf of Mexico in
accordance with various purchase and sale contracts with producers served by our
pipeline. We buy crude oil at various points along the pipeline and resell the
crude oil at a destination point in accordance with each individual contract.
Our margin is earned based upon the differential between the sales price and the
purchase price and represents our earnings from providing transportation
services. Differences between measured purchased and sold volumes in any period
are recorded as changes in exchange imbalances with producers. In addition, we
transport crude oil for a fee.

Basis of Presentation

Our financial statements are prepared on the accrual basis of accounting in
conformity with accounting principles generally accepted in the United States.
Our financial statements for previous periods include reclassifications that
were made to conform to the current year presentation. Those reclassifications
have no impact on reported net income or members' capital.

Cash and Cash Equivalents

We consider short-term investments with little risk of change in value
because of changes in interest rates and purchased with an original maturity of
less than three months to be considered cash equivalents.

Debt Reserve Fund

In connection with our revolving credit facility, we are required to
maintain a debt reserve account as collateral on the outstanding balances. At
December 31, 2002 and 2001, the balance in the account was approximately $3.6
million and $3.5 million, and consisted of funds earning interest at 1.5% and
1.7%.

Allowance for Doubtful Accounts

Collectibility of accounts receivable is reviewed regularly and an
allowance is recorded as necessary, primarily under the specific identification
method. At December 31, 2002 and 2001, no allowance for doubtful accounts was
recorded.

Property, Plant and Equipment

Contributed property, plant and equipment is recorded at fair value as
agreed to by the members at the date of contribution. Acquired property, plant
and equipment is recorded at cost. Pipeline equipment is depreciated using a
composite, straight-line method over the estimated useful lives of 3 to 30
years. Line-fill is not depreciated, as our management believes the cost of all
barrels is fully recoverable. Repair and maintenance costs are expensed as
incurred, while additions, improvements and replacements are capitalized. No
gain or loss is recognized on normal asset retirements under the composite
method.
172

POSEIDON OIL PIPELINE COMPANY, L.L.C.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

Impairment and Disposal of Long-Lived Assets

We adopted the provisions of Statement of Financial Accounting Standards
(SFAS) No. 144 Accounting for the Impairment or Disposal of Long-Lived Assets on
January 1, 2002. Accordingly, we evaluate the recoverability of selected
long-lived assets when adverse events or changes in circumstances indicate that
the carrying value of an asset or group of assets may not be recoverable. We
determine the recoverability of an asset or group of assets by estimating the
undiscounted cash flows expected to result from the use and eventual disposition
of the asset or group of assets at the lowest level for which separate cash
flows can be measured. If the total of the undiscounted cash flows is less that
the carrying amount for the assets, we estimate the fair value of the asset or
group of assets and recognize the amount by which the carrying value exceeds the
fair value as an impairment loss in income from operations in the period the
impairment is determined. Our adoption of SFAS No. 144 did not have a material
impact on our financial position or result of operations.

Additionally, as required by SFAS No. 144, we classify long-lived assets to
be disposed of other than by sale (e.g., abandonment, exchange or distribution)
as held and used until the item is abandoned, exchanged or distributed. We
evaluate assets to be disposed of other than by sale for impairment and
recognize a loss for the excess of the carrying value over the fair value.
Long-lived assets to be disposed of through sale recognition meeting specific
criteria are classified as "Held for Sale" and measured at the lower of their
cost or fair value less cost to sell. We report the results of operations of a
component classified as held for sale, including any gain or loss recognized in
discontinued operations in the period(s) in which they occur and all prior
periods presented.

Debt Issue Costs

Debt issue costs are capitalized and amortized over the life of the related
indebtedness. Any unamortized debt issue costs are expensed at the time the
related indebtedness is repaid or terminated. As of December 31, 2002 and 2001,
debt issue costs of $415 thousand and $708 thousand are classified as an other
noncurrent asset on our balance sheet.

Fair Value of Financial Instruments

The estimated fair values of our cash and cash equivalents, accounts
receivable and accounts payable approximate their carrying amounts in the
accompanying balance sheet due to the short-term maturity of these instruments.
The fair value of our long-term debt with variable interest rates approximates
its carrying value because of the market-based nature of the debt's interest
rates.

Revenue Recognition

Revenue from crude oil sales is recognized upon delivery. Revenue from
pipeline transportation of hydrocarbons is recognized upon receipt of the
hydrocarbons into the pipeline system.

Comprehensive Income

Our comprehensive income is determined based on net income (loss), adjusted
for changes in accumulated other comprehensive income (loss) from our cash flow
hedging activities associated with our interest rate hedge for our revolving
credit facility.

Crude Oil Imbalances

In the course of providing transportation services for customers, we may
receive different quantities of crude oil than the quantities delivered. These
transactions result in imbalances that are settled in kind the following month.
We value our imbalances based on the weighted average acquisition price of
produced

173

POSEIDON OIL PIPELINE COMPANY, L.L.C.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

barrels for the current month. Our imbalance receivables and imbalance payables
were classified on our balance sheet as follows on December 31 (in thousands):

Environmental Costs

Expenditures for ongoing compliance with environmental regulations that
relate to current operations are expensed or capitalized as appropriate.
Expenditures that relate to an existing condition caused by past operations, and
which do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments indicate that
remediation efforts are probable and the costs can be reasonably estimated.

Accounting for Hedging Activities

We apply the provisions issued in SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities to account for price risk management
activities. This statement requires us to measure all derivative instruments at
their fair value, and classify them as either assets or liabilities on our
balance sheet, with the corresponding offset to income or other comprehensive
income depending on their designation, their intended use, or their ability to
qualify as hedges under the standard. As of December 31, 2002, the fair value of
our interest rate swap was a liability of $1.4 million resulting in accumulated
other comprehensive loss of $1.4 million.

In January 2002, we entered into a two-year interest rate swap agreement
with Credit Lyonnais to fix the variable LIBOR based interest rate on $75
million of our variable rate revolving credit facility at 3.49% through January
2004. Under our credit facility, we currently pay an additional 1.50% over the
LIBOR rate resulting in an effective interest rate of 4.99% on the hedged
notional amount. Collateral was not required and we do not anticipate
non-performance by the counter party.

Income Taxes

We are organized as a Delaware limited liability company and treated as a
partnership for income tax purposes, and as a result, the income or loss
resulting from our operations for income tax purposes is included in the federal
and state tax returns of our members. Accordingly, no provision for income taxes
has been recorded in the accompanying financial statements.

Management's Use of Estimates

The preparation of our financial statements in conformity with accounting
principles generally accepted in the United States requires us to make estimates
and assumptions that effect the reported amounts of assets, liabilities,
revenues and expenses, and disclosure of contingent assets and liabilities that
exist at the date of our financial statements. While we believe our estimates
are appropriate, actual results can, and often do, differ from those estimates.

174

POSEIDON OIL PIPELINE COMPANY, L.L.C.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

Income Allocation and Cash Distributions

Our income is allocated to our members based on their ownership
percentages. At times, we may make cash distributions to our members in amounts
determined by our Management Committee, which is responsible for conducting our
affairs in accordance with our limited liability agreement.

Limitations of Member's Liability

As a limited liability company, our members or their affiliates are not
personally liable for any of our debts, obligations or liabilities simply
because they are our members.

Business Combinations

In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 141, Business Combinations. This statement requires that all transactions
that fit the definition of a business combination be accounted for using the
purchase method and prohibits the use of the pooling of interests method for all
business combinations initiated after June 30, 2001. This statement also
established specific criteria for the recognition of intangible assets
separately from goodwill and requires unallocated negative goodwill to be
written off immediately as an extraordinary item. The accounting for any
business combinations we undertake in the future will be impacted by this
standard. Our adoption of SFAS No. 141 did not have a material effect on our
financial position or results of operations.

Accounting for Asset Retirement Obligations

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations. This statement requires companies to record a liability for the
estimated retirement and removal of assets used in their business. The liability
is discounted to its present value, and the related asset value is increased by
the amount of the resulting liability. Over the life of the asset, the liability
will be accreted to its future value and eventually extinguished when the asset
is taken out of service. Capitalized retirement and removal costs will be
depreciated over the useful life of the related asset. The provisions of this
statement are effective for fiscal years beginning after June 15, 2002. We are
required to adopt the provisions of SFAS No. 143 as of January 1, 2003 and will
record an adjustment for the cumulative effect of initially adopting this
statement in our statement of income. Our adoption of this statement will not
have a material effect on our financial position or results of operations.

Reporting Gains and Losses from the Early Extinguishment of Debt

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements
No. 4, 44, and 64. Amendment of FASB Statement No. 13, and Technical
Corrections. This statement addresses how to report gains or losses resulting
from the early extinguishment of debt. Previously, any gains or losses were
reported as an extraordinary item. Upon adoption of SFAS No. 145, an entity will
be required to evaluate whether the debt extinguishment is truly extraordinary
in nature, in accordance with Accounting Principles Board Opinion No. 30. If the
entity routinely extinguishes debt early, the gain or loss should be included in
income from continuing operations. This statement is effective for our 2003
year-end reporting.

Accounting for Costs Associated with Exit or Disposal Activities

In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities. This statement requires companies to recognize
costs associated with exit or disposal activities when they are incurred rather
than at the date of a commitment to an exit or disposal plan. Examples of costs
covered by this guidance include lease termination costs and certain employee
severance costs that are associated with a restructuring, discontinued
operation, plant closing, or other exit or disposal activity. The

175

POSEIDON OIL PIPELINE COMPANY, L.L.C.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

provisions of this statement are effective for fiscal years beginning after
December 31, 2002. The provisions of this statement will impact any exit or
disposal activities that we initiate after January 1, 2003.

Accounting for Guarantees

In November 2002, the FASB issued FASB Interpretation (FIN) No. 45,
Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others. This interpretation requires that
companies record a liability for all guarantees issued or modified after
December 31, 2002, including financial, performance, and fair value guarantees.
This liability is recorded at its fair value upon issuance, and does not affect
any existing guarantees issued before January 31, 2003. This standard also
requires expanded disclosures on all existing guarantees at December 31, 2002.
We do not currently guarantee the indebtedness of others; however the
recognition, measurement and disclosure provisions of this interpretation will
apply to any guarantees we may make in the future.

Consolidation of Variable Interest Entities

In January 2003, the FASB issued FIN No. 46, Consolidation of Variable
Interest Entities. This interpretation defines a variable interest entity as a
legal entity whose equity owners do not have sufficient equity at risk and/or a
controlling financial interest in the entity. This standard requires that
companies consolidate a variable interest entity if it is allocated a majority
of the entity's losses and/or returns, including fees paid by the entity. The
provisions of FIN No. 46 are effective for all variable interest entities
created after January 31, 2003, and are effective on July 1, 2003 for all
variable interest entities created before January 31, 2003. Our adoption of this
statement will not have a material effect on our financial position or results
of operations.

NOTE 2 -- PROPERTY, PLANT AND EQUIPMENT

Our property, plant and equipment consisted of the following:

During 2002 and 2001, we did not capitalize interest costs into property,
plant and equipment.

NOTE 3 -- LONG-TERM DEBT

In April 2001, we amended and restated our revolving credit facility to
provide up to $185 million for construction and expansion of our system and for
other working capital changes. Our ability to borrow money under this facility
is subject to certain customary terms and conditions, including borrowing base
limitations, and we are required to maintain a debt service reserve equal to two
quarters' interest. This facility is collateralized by a substantial portion of
our assets and matures in April 2004. As of December 31, 2002, and 2001, we had
$148 million and $150 million outstanding under this facility with the full
unused amount available. The average variable floating interest rate was 3.4%
and 3.9% at December 31, 2002 and 2001. We pay a variable commitment fee on the
unused portion of the credit facility. The fair value of our revolving credit
facility with variable interest rates approximates its carrying value because of
the market based nature of

176

POSEIDON OIL PIPELINE COMPANY, L.L.C.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

our debt's interest rates. During the first quarter of 2003, we reduced the
outstanding balance of our revolving credit facility by $21 million.

Our revolving credit facility contains covenants such as restrictions on
debt levels, restrictions on liens securing debt and guarantees, restrictions on
mergers and on the sales of assets and dividend restrictions. A breach of any of
these covenants could result in acceleration of our debt and other financial
obligations.

Under our revolving credit facility, the financial debt covenants are:

(a) we must maintain consolidated tangible net worth in an amount not less
than $75 million plus 100% of the net cash proceeds from our issuance
of equity securities of any kind;

(b) the ratio of EBITDA, as defined in our credit facility, to interest
expense paid or accrued during the four quarters ending on the last
day of the current quarter must be at least 2.50 to 1.00; and

(c) the ratio of our total indebtedness to EBITDA, as defined in our
credit facility, for the four quarters ending on the last day of the
current quarter shall not exceed 3.00 to 1.00.

We are in compliance with the above covenants as of the date of this
filing.

In January 2002, we entered into a two-year interest rate swap to fix the
variable LIBOR based interest rate on $75 million of our revolving facility at
3.49 percent through January 2004. Under our credit facility, we currently pay
an additional 1.50% over the LIBOR rate resulting in an effective rate of 4.99%
on the hedged notional amount.

We use interest rate swaps to limit our exposure to fluctuations in
interest rates. These interest rate swaps are accounted for in accordance with
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. As
of December 31, 2002, the fair value of our interest rate swap was a liability
of $1.4 million resulting in accumulated other comprehensive loss of $1.4
million. The entire amount will be reclassified from accumulated other
comprehensive income to earnings proportionately over the next twelve months.
Additionally, we have recognized in income a realized loss of $1.2 million for
the twelve months ended December 31, 2002, as interest expense.

177

POSEIDON OIL PIPELINE COMPANY, L.L.C.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 4 -- MAJOR CUSTOMERS

The percentage of our transportation services and crude oil sales revenues
from major customers were as follows:

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

(1) Represents affiliated companies.

NOTE 5 -- RELATED PARTY TRANSACTIONS

We derive a portion of our gross sales and gross purchases from our members
and their affiliated companies. We generated approximately $449 million and $489
million in gross affiliated sales and approximately $434 million and $489 in
gross affiliated purchases for 2002 and 2001.

We paid Manta Ray Gathering Company, L.L.C., a subsidiary of El Paso Energy
Partners, approximately $2.1 million for management, administrative and general
overhead in 2002 and in 2001. Prior to Manta Ray Gathering Company, L.L.C.,
taking over as operator, Shell received approximately $1.1 million in 2000 for
management, administrative and general overhead. During 2000, we were charged
and paid Shell an additional management fee of approximately $1.7 million
associated with the repair of our ruptured pipeline. Our other members disputed
this additional charge and we were subsequently reimbursed $1.6 million in 2001.

NOTE 6 -- COMMITMENTS AND CONTINGENCIES

Legal

In the normal course of business, we are involved in various legal actions
arising from our operations. In the opinion of management, the outcome of these
legal actions will not have a significant adverse effect on our financial
position or results of operations.

Environmental

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. We have no reserves for environmental matters, and during the next five
years, we do not expect to make any significant capital expenditures relating to
environmental matters.

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

178

POSEIDON OIL PIPELINE COMPANY, L.L.C.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

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.

Other

We 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 and regulation under the
Hazardous Liquid Pipeline Safety Act. Operations in offshore federal waters are
regulated by the United States Department of the Interior.

In February 1998, we entered into an oil purchase and sale agreement with
Pennzoil Exploration and Production (Pennzoil). The agreement provides that if
Pennzoil delivers at least 7.5 million barrels by September 2003, we will refund
$0.51 per barrel for all barrels delivered plus interest at 8 percent. At
December 31, 2002, we believe that we have no obligation under this agreement.
Also, in December 2001, based on barrels delivered through December 31, 2001 and
our estimates through September 2003, we believed Pennzoil would not meet its
minimum delivery requirement. Accordingly, we reversed our accrual for revenue
refund of $1.7 million at December 31, 2001 and recorded it as a component of
operating revenue in 2001.

In January 2000, an anchor from a submersible drilling unit of Transocean
96 (Transocean) in tow ruptured our 24-inch crude oil pipeline north of the Ship
Shoal 332 platform. The accident resulted in the release of approximately 2,200
barrels of crude oil in the waters surrounding our system, caused damage to the
Ship Shoal 332 platform, and resulted in the shutdown of our system. Our cost to
repair the damaged pipeline and clean up the crude oil released into the Gulf of
Mexico was approximately $18 million and was charged to repair expenses in the
year ended December 31, 2000. By the end of the first quarter 2000, our pipeline
was repaired and placed back into service. In November 2002, we reached a
settlement with multiple parties relating to this rupture and have recorded the
proceeds of $26.6 million as other income in our 2002 statement of income.

179

SCHEDULE II

EL PASO ENERGY PARTNERS, L.P.

VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(IN THOUSANDS)

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

(1) Our environmental reserve is for environmental liabilities assumed in our
EPN Holding asset acquisition during 2002. This reserve was included in our
allocation of the purchase price for the acquisition.

180

EL PASO ENERGY PARTNERS, L.P.

EXHIBIT LIST
DECEMBER 31, 2002

Each exhibit identified below is filed as a part of this Annual Report.
Exhibits included in this filing are designated by an asterisk; all exhibits not
so designated are incorporated herein by reference to a prior filing as
indicated. Exhibits designated with a "+" constitute a management contract or
compensatory plan or arrangement required to be filed as an exhibit to this
report pursuant to Item 15(c) of Form 10-K.

181

182

183

(b) REPORTS ON FORM 8-K

- We filed a current report on Form 8-K dated November 15, 2002 to update
the financial statements and pro forma financial information filed in
connection with the proposed San Juan assets acquisition from El Paso
Corporation, as well as the proposed financing plan.

- We filed a current report on Form 8-K dated December 2, 2002 to announce
the completion of the acquisition of the San Juan assets from El Paso
Corporation on November 27, 2002.

- We filed a current report on Form 8-K dated December 11, 2002 disclosing
our acquisition of the San Juan assets from El Paso Corporation on
November 27, 2002.

- We filed a current report on Form 8-K dated December 26, 2002 to amend
the Form 8-K dated December 11, 2002, and to update the pro forma
financial information previously filed in our Current Reports on Form
8-K.

- We filed a current report on Form 8-K dated January 2, 2003 to
incorporate Amendment No. 1 to El Paso Energy Partners, L.P.'s Annual
Report on Form 10-K for the year ended December 31, 2001 into the Form
8-K/A filed July 19, 2002, which was filed to conform our historical
financial presentation and the changes in our segment presentation in our
Form 10-Q for the quarterly period ended March 31, 2002.

- We filed a current report on Form 8-K dated March 19, 2003 to update our
current risk factors discussion and to provide additional information
relating to us, our operations and our relationship with El Paso
Corporation.

184

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, as amended, El Paso Energy Partners, L.P. has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly
authorized on the twenty-seventh day of March 2003.

EL PASO ENERGY PARTNERS, L.P.
(Registrant)

By: EL PASO ENERGY PARTNERS COMPANY,
its General Partner

By: /s/ ROBERT G. PHILLIPS
-------------------------------------
Robert G. Phillips
Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, this report has been signed below by the following persons on behalf of
El Paso Energy Partners, L.P. and in the capacities and on the dates indicated:

185

CERTIFICATION

I, Robert G. Phillips, certify that:

1. I have reviewed this annual report on Form 10-K of El Paso Energy
Partners, L.P.;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;

(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this annual report (the "Evaluation Date"); and

(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal controls;
and

(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

Date: March 27, 2003

/s/ ROBERT G. PHILLIPS
--------------------------------------
Robert G. Phillips
Chief Executive Officer
El Paso Energy Partners Company,
general partner of El Paso Energy
Partners, L.P.

186

CERTIFICATION

I, Keith B. Forman, certify that:

1. I have reviewed this annual report on Form 10-K of El Paso Energy
Partners, L.P.;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;

(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this annual report (the "Evaluation Date"); and

(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal controls;
and

(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

Date: March 27, 2003

/s/ KEITH B. FORMAN
--------------------------------------
Keith B. Forman
Chief Financial Officer
El Paso Energy Partners Company,
general partner of El Paso Energy
Partners, L.P.

187

EL PASO ENERGY PARTNERS, L.P.

INDEX TO EXHIBITS
DECEMBER 31, 2002

Each exhibit identified below is filed as a part of this Annual Report.
Exhibits included in this filing are designated by an asterisk; all exhibits not
so designated are incorporated herein by reference to a prior filing as
indicated. Exhibits designated with a "+" constitute a management contract or
compensatory plan or arrangement required to be filed as an exhibit to this
report pursuant to Item 15(c) of Form 10-K.