GULFTERRA ENERGY PARTNERS L P - 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, 2003

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

GULFTERRA 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) 676-4853

INTERNET WEBSITE: WWW.GULFTERRA.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. [X]

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 59,623,667 COMMON UNITS OUTSTANDING AS OF MARCH 10,
2004. THE AGGREGATE MARKET VALUE ON MARCH 10, 2004 AND JUNE 30, 2003 OF THE
REGISTRANT'S COMMON UNITS HELD BY NON-AFFILIATES WAS APPROXIMATELY $2,450
MILLION AND $1,869 MILLION.

DOCUMENTS INCORPORATED BY REFERENCE: NONE
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GULFTERRA 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 public and private
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 (NGLs). 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 Louisiana, Mississippi
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 New Mexico. These regions, especially the deeper
water regions of the Gulf of Mexico, one of the United States' fastest growing
oil and 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.
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As generally used in the energy industry and in this document, the identified
terms have the following meanings:

/d = per day
Bbl = barrel
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

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 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. 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 own or have interests in:

- over 15,500 miles of natural gas gathering and transportation pipelines
with capacity of over 10.9 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 160
MBbls/d;

- five natural gas processing/treating plants with capacity of over 1.5
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 25 MMBbls;

- three natural gas storage facilities with aggregate working gas capacity
of approximately 20 Bcf; and

- seven offshore hub platforms.

In addition, we currently have midstream projects underway in the Gulf of
Mexico with gross estimated capital costs of approximately $862 million,
including 426 miles of oil pipelines and 151 miles of natural gas pipelines.

To further our business strategy, we executed definitive agreements with
Enterprise Products Partners L.P. (Enterprise) and El Paso Corporation, on
December 15, 2003, to merge Enterprise and GulfTerra to form one of the largest
publicly traded MLPs with an enterprise value of approximately $13 billion as of
December 15, 2003.

For further discussion of the merger and related transactions, see Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations.

SEGMENTS

We have segregated our business activities into four distinct operating
segments:

- Natural gas pipelines and plants;

- Oil and NGL logistics;

- Natural gas storage; and

- Platform services.

These segments are strategic business units that provide a variety of
energy related services. For information relating to revenues from external
customers, operating income and total assets of each segment, see Item 8,
Financial Statements and Supplementary Data, Note 15. Each of these segments is
discussed more fully below.

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NATURAL GAS PIPELINES AND PLANTS

Natural Gas Pipelines Systems

We own interests in natural gas pipeline systems extending over 15,500
miles, with a combined maximum design capacity (net to our interest) of over
10.9 Bcf/d of natural gas. We own or have interests in gathering systems onshore
in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas, including
the San Juan gathering system in New Mexico and the Texas Intrastate system. In
addition to our onshore natural gas pipeline systems, our offshore natural gas
pipeline systems are strategically located to serve production activities in
some of the most active drilling and development regions in the Gulf of Mexico,
including select locations offshore of Texas, Louisiana and Mississippi, and to
provide relatively low cost access to long-line transmission pipelines that
access multiple markets in the eastern half of the United States.

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

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(1) The average throughput reflects 100 percent of the throughput. We acquired
the San Juan gathering system and the Typhoon natural gas pipeline in
November 2002. The Typhoon natural gas pipeline was placed in service in
August 2001.

(2) The average throughput reflects 100 percent of the throughput. We acquired
the Texas Intrastate system and the Permian Basin system in April 2002.

(3) The Texas Intrastate system is comprised of the GulfTerra Texas Intrastate,
the TPC Offshore and the Channel pipeline systems. The Railroad Commission
of Texas regulates the rates of the GulfTerra Texas and Channel systems. The
Federal Energy Regulatory Commission (FERC) regulates the Section 311 rates
of the GulfTerra Texas system, the Channel system and GulfTerra Alabama
Intrastate. HIOS is also regulated by the FERC as an interstate pipeline
under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978.

(4) In the fourth quarter of 2003, we completed the 37-mile Medusa extension of
our Viosca Knoll gathering system.

(5) 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.

(6) The Falcon gas pipeline went into service in March 2003.

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

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

San Juan Gathering System. The San Juan natural gas gathering system, which
we acquired in November 2002, is located in the San Juan Basin and has
connections to approximately 10,000 wells. The system gathers natural gas from
wells in the San Juan Basin to our Chaco plant and to the BP and Conoco owned
Blanco plant. Over 70% of the gathering revenues from the system come from
gathering agreements with Burlington, BP and Conoco. 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 System. 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 563 miles of predominantly 4-inch to
12-inch pipelines.

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

- GulfTerra Texas Intrastate. The GulfTerra Texas Intrastate natural gas
gathering system is one of the largest intrastate pipeline systems in the
United States based on miles of pipe. 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 GulfTerra Texas
Intrastate system also 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 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.

GulfTerra Alabama Intrastate System. GulfTerra Alabama Intrastate is a
natural gas pipeline system that serves the coal bed methane producing regions
of Alabama. GulfTerra Alabama Intrastate 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.

Viosca Knoll Gathering System. The Viosca Knoll gathering 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. In the fourth quarter of 2003, we
completed a 37-mile gas pipeline extension of our Viosca Knoll gathering system
with capacity to handle 160 MMcf/d of natural gas production from Murphy
Exploration and Production Company's Medusa field in the Gulf of Mexico.
Production from the Medusa field into our pipeline extension began in November
2003. TotalFinaElf's Matterhorn field was also connected to our Viosca Knoll
gathering system in 2003. TotalFinaElf, at their expense, constructed a
gathering pipeline from their Matterhorn tension leg platform to our gathering
system. Production from the Matterhorn field into the Viosca Knoll gathering
system also began in November 2003.

High Island Offshore System. HIOS 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 connects
the Hoover-Diana deepwater platform, owned by subsidiaries of ExxonMobil and BP
and located in Alaminos Canyon Block 25, to HIOS.

Falcon Gas Pipeline. The Falcon gas pipeline gathers Pioneer Natural
Resources' natural gas that is processed at our Falcon Nest platform to a
connection with the Central Texas Gathering System located on the Brazos
Addition Block 133 platform.

Typhoon Gas Pipeline. The Typhoon gas pipeline, which we acquired in
November 2002, is an offshore natural gas pipeline that connects the Typhoon
platform 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 project, which is in the
construction phase.

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Natural Gas Processing and Treating Facilities

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

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

(2) 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.

(3) All capacity measures are on a MMcf/d basis. Indian Basin and Coyote are
reflected at 100 percent 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 $600 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 extracting up to 50
MBbls/d of NGL.

Construction Projects

Phoenix Gathering System. We are constructing and will own 100 percent of
a new $66 million 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 subsidiaries of Kerr-McGee Corporation and
Devon Energy, Inc., which each hold a 50-percent working interest in the Red
Hawk Field. Kerr-McGee and Devon 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 platform and connect to the ANR Patterson
Offshore Pipeline system at Vermillion Block 397. We plan to place the new
pipeline in service mid-year 2004. As of December 31, 2003, we have spent
approximately $51.7 million related to this pipeline, which is in the
construction stage. We expect to receive contributions in aid of construction
from ANR Pipeline Company, a subsidiary of El Paso Corporation, of $6.1 million,
of which $3.0 million has been collected, for the benefits of increased volumes
they expect to transport on their pipeline as a result of our construction of
this pipeline.

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Marco Polo -- Gas Gathering System. We are constructing and will own 100
percent of a 75-mile, 18-inch and 20-inch natural gas gathering system to
support the Marco Polo tension-leg platform (TLP). The natural gas gathering
system, 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 gathering system in Green Canyon Block 237. We intend to integrate
the Marco Polo natural gas gathering system and Typhoon natural gas gathering
system. This gathering system is expected to be completed and placed in service
mid-year 2004, and is expected to cost $72 million to construct. We incurred
higher costs of $4 million than originally anticipated as the result of
installation timing conflicts between the Marco Polo TLP installation and the
Marco Polo gas pipeline installation. As of December 31, 2003, we have spent
approximately $47.0 million on this gathering system, which is in the
construction stage. Additionally, we received contributions in aid of
construction from ANR Pipeline Company and El Paso Field Services, subsidiaries
of El Paso Corporation, totaling $17.5 million for the benefits of increased
volumes they anticipate receiving on their facilities as a result of our
construction of the natural gas pipeline.

San Juan Optimization Project. In May 2003, we commenced a $43 million
project relating to our San Juan Basin assets. The project is expected to be
completed in stages through 2006. The project is expected to result in increased
capacity of up to 130 MMcf/d on the San Juan gathering system and increased
market opportunities through a new interconnect at the tailgate of our Chaco
plant. As of December 31, 2003, we have spent approximately $1.8 million related
to this project.

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.

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 2003 and 2002 is
attributable to three customers, Burlington Resources, ConocoPhillips and BP.
These contracts expire in December of 2008, 2006 and 2006. The following table
indicates the percentage revenue generated by each contract in relation to the
indicated denominator for the years ended December 31, 2003 and 2002:

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(1) The average throughput reflects 100 percent of the throughput. We acquired
the Typhoon oil pipeline in November 2002.

(2) All capacity measures are on a MBbls/d basis. Poseidon, Typhoon 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.

Poseidon System. Poseidon is a major offshore sour crude oil pipeline
system that gathers production from the outer continental shelf in the Gulf of
Mexico and transports onshore to Houma, Louisiana. The Poseidon system is owned
by Poseidon Oil Pipeline Company, L.L.C., in which we own a 36 percent
membership interest.

Allegheny System. Our Allegheny system is an offshore crude oil system
consisting of 43 miles of 14-inch diameter pipeline that connects the Allegheny
platform in the Green Canyon area of the Gulf of

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Mexico with Poseidon at our 50 percent owned Ship Shoal 332 platform. Oil
production from the Allegheny field is committed to this system. In addition,
Allegheny will receive production gathered from our Marco Polo oil pipeline.

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 platform in the Green Canyon area of the Gulf of Mexico to the Shell
Boxer platform. The Shell Boxer platform provides access to the Poseidon
pipeline through a third party pipeline and access to two other third party
pipelines.

NGL Transportation, Fractionation and Related Storage Facilities

We own more than 1,000 miles of intrastate NGL gathering and transportation
pipelines and four fractionation plants located in Texas. The NGL pipeline
system includes 379 miles of pipeline used to gather and transport
unfractionated NGL from various processing plants to the Shoup Plant, located in
Corpus Christi, which is the largest of our four fractionators. The pipeline
system also includes over 660 miles of pipelines that deliver fractionated
products such as ethane, propane, butane and natural gasoline to refineries and
petrochemical plants from Corpus Christi to Houston and within the Texas
City-Houston area, as well as to common carrier NGL pipelines. A key service
provided for these customers is the seasonal movement of butanes to and from our
leased underground NGL storage from refineries in Corpus Christi and Texas City.
Our four Texas fractionation facilities have a combined capacity of 120 MBbls/d.
Utilization rates in the fractionation industry can fluctuate dramatically from
month to month, depending on the needs of our producer and refinery customers.
However, the average utilization rate for three of our fractionators (excluding
our Almeda fractionator) for the years ended December 31, 2003, 2002 and 2001
was 59 percent, 74 percent and 73 percent. The average utilization rate for the
Almeda fractionator for the years ended December 31, 2003, 2002 and 2001 was 9
percent, less than 2 percent and 32 percent; the utilization for 2003 and 2002
was negatively impacted due to refurbishment work at the facility.

We also own a 3.3 MMBbl propane storage business operation located in
Hattiesburg, Mississippi and a 3.2 MMBbl multi-product NGL storage facility near
Breaux Bridge, Louisiana. We entered into a long-term propane storage agreement
with Suburban Propane, L.P. for a portion of the storage capacity in
Mississippi. A significant portion of the storage capacity of the Louisiana
facility is committed under long-term storage agreements with a third party and
with El Paso Field Services, a subsidiary of El Paso Corporation. Additionally,
in November 2002, we acquired leases for two 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

Cameron Highway. We are constructing the $458 million, 390-mile Cameron
Highway oil pipeline with capacity of 500 MBbls/d, which is expected to be in
service by the fourth 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.

Cameron Highway Oil Pipeline Company, our 50/50 joint venture with Valero
Energy Corporation, will own the pipeline. We entered into producer agreements
with three major anchor producers, BP Exploration & Production Company, BHP
Billiton Petroleum (Deepwater), Inc. and Union Oil Company of California, which
agreements were assigned to and assumed by Cameron Highway when Valero purchased
its interest in the joint venture. The producer agreements require construction
of the 390-mile Cameron Highway oil pipeline.

Cameron Highway has a $325 million project loan facility for the Cameron
Highway oil pipeline system project, consisting of a $225 million construction
loan and $100 million of senior secured notes. See Item 8, Financial Statements
and Supplementary Data, Note 6, for additional discussion of the project loan
facility. As of December 31, 2003, Cameron Highway has spent approximately $256
million (of which $85 million constituted equity contributions by us) related to
this pipeline, which is in the construction stage. We and
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Valero are obligated to make additional capital contributions to Cameron Highway
if and to the extent that the construction costs for the pipeline exceed Cameron
Highway's capital resources, including the initial equity contributions and
proceeds from Cameron Highway's project loan facility.

Marco Polo -- Oil Pipeline. We are constructing and will own 100 percent
of a 36-mile, 14-inch oil pipeline to support the Marco Polo TLP. The oil
pipeline will gather oil from the Marco Polo platform into 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 mid-year 2004, and
is expected to cost $34 million to construct. We incurred higher costs than
originally anticipated as a result of construction down time as a result of
weather related delays and strong sea currents. As of December 31, 2003, we have
spent approximately $25.7 million on this pipeline, which is in the construction
stage.

Front Runner Oil Pipeline. In September 2003, we announced that Poseidon,
our 36 percent owned joint venture, entered into an agreement for the purchase
and sale of crude oil from the Front Runner Field. Poseidon will construct, own
and operate the $28 million project, which will connect the Front Runner
platform with Poseidon's existing system at Ship Shoal Block 332. The new
36-mile, 14-inch pipeline is expected to be operational by the third quarter of
2004 and have a capacity of 65 MBbls/d. As Poseidon expects to fund Front
Runner's capital expenditures from its operating cash flow and from its
revolving credit facility, we do not expect to receive distributions from
Poseidon until the Front Runner oil pipeline is completed.

Markets and Competition

Our offshore oil pipeline systems were built as a result of the need for
additional crude oil capacity to receive and deliver 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. 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 pipeline 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.

Our Texas fractionation facilities typically experience a base utilization
rate of approximately 60% to 70% because most of the natural gas in south Texas
must be processed to extract heavier NGLs, such as butane and natural gasoline,
in order to meet the quality specifications of the downstream natural gas
pipelines; however, full utilization of our fractionation facilities occurs only
when the natural gas producer can receive more net proceeds by maximizing the
extraction and selling the lighter NGLs, such as ethane and propane, contained
in the raw natural gas stream. The spread between natural gas and NGL prices
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 natural 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 natural gas quality specifications.
Regardless of the elections made by the producers, our fractionation facilities
would continue to be operated, but at varying utilization levels. We will
continue to incur operating costs regardless of the utilization level.

All of the capacity of our GTM Texas fractionation facilities is dedicated
to a subsidiary of El Paso Corporation under a transportation and fractionation
agreement that expires in 2021. In this
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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 (which plants El Paso Corporation has agreed to sell to Enterprise
in connection with our proposed merger) 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.
Until our merger with Enterprise closes, El Paso Corporation's subsidiary will
bear substantially all of the risks and rewards associated with changes in the
commodity prices for NGL.

For a discussion of our significant customers, see Item 8, Financial
Statements and Supplementary Data, Note 14.

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. We have ongoing programs designed to keep our oil and NGL logistics
operations in compliance with environmental and safety requirements, and we
believe that our facilities are in material compliance with the applicable
requirements. 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 GTM
Texas, Allegheny, Typhoon and Poseidon pipelines is maintained through regular
cleaning utilizing polyurethane pigs. Corrosion inhibitors are also injected
into the GTM Texas system through the flow stream on a continuous basis. To
maintain our pipeline integrity on our Poseidon, Allegheny and Typhoon oil
pipeline systems, we use water sample analysis, electron microscope analysis and
a rigid pigging schedule. Our Allegheny, Typhoon 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.

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 an
8.9 Bcf (6.3 Bcf working capacity) expansion of our Petal facility, including a

12

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. Additionally, we lease the Wilson natural gas storage facility. Each
of these facilities is capable of making deliveries at the high rates necessary
to satisfy peak requirements in the electric generation industry.

- ----------

(1) 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 rate at the time of renewal.

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 94
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 1.95 Bcf subscribed to BP Energy Company.

The Wilson facility interconnects with our Texas Intrastate systems and is
located in Wharton County, Texas, and consists of four caverns. 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 97 percent subscribed with long-term contracts expiring between 2006
and 2007.

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.

Construction Projects

Petal Expansion Project. In September 2003, we entered into a nonbinding
letter of intent with Southern Natural Gas Company, a subsidiary of El Paso
Corporation, regarding the proposed development and sale of a natural gas
storage cavern and the proposed sale of an undivided interest in a pipeline and
other

13

facilities related to that natural gas storage cavern. The new storage cavern
would be located at our storage complex near Hattiesburg, Mississippi. If
Southern Natural Gas determines that there is sufficient market interest, it
would purchase the land and mineral rights related to the proposed storage
cavern and would pay our costs to construct the storage cavern and related
facilities. Upon completion of the storage cavern, Southern Natural Gas would
acquire an undivided interest in our Petal pipeline connected to the storage
cavern. We would also enter into an arrangement with Southern Natural Gas under
which we would operate the storage cavern and pipeline on its behalf. Southern
Natural Gas is holding an open season for the space.

Before we consummate this transaction, and enter into definitive
transaction documents, the transaction must be recommended by the audit and
conflicts committee of our general partner's board of directors, which committee
consists solely of directors meeting the independent director requirements
established by the NYSE and the Sarbanes-Oxley Act and then approved by our
general partner's full board of directors.

We are also considering converting our existing brine well at our propane
storage caverns in Hattiesburg to natural gas service. This conversion would
cost approximately $16 million and would create a new 1.8 Bcf working natural
gas cavern that would be integrated into our Petal storage complex. We are
currently negotiating with customers for the full 1.8 Bcf of capacity and
expect, subject to final regulatory approval, to have the cavern in service
during the fourth quarter of 2004.

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 the Hattiesburg
and Wilson natural gas storage assets are long term, expiring between 2005 and
2007. 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 Part II, Item 8,
Financial Statements and Supplementary Data, Note 14.

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.

14

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 natural 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 the final rule regarding marketing affiliates which
will affect our Petal operations. See Part II, Item 8, Financial Statements and
Supplementary Data, Note 11.

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 Health Act, the Emergency Planning and
Community Right-to-Know Act, and similar state statutes. We have ongoing
programs designed to keep our storage operations in compliance with
environmental and safety regulations, and we believe that our facilities are in
material compliance with the applicable requirements. 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 in accordance with 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.

15

We have interests in seven multi-purpose offshore hub platforms in the Gulf
of Mexico, including the Falcon Nest platform that we brought on line in March
2003 and the Marco Polo tension leg platform (TLP) that was installed in January
2004. These platforms were specifically designed to be used as 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) Primarily serves as a junction platform for pipeline interconnects.
(2) The Marco Polo TLP is expected to be in service in the second quarter of
2004.

East Cameron 373. The East Cameron 373 platform is located at the south end
of the central leg of the 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 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 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. The Falcon Nest fixed-leg platform, located at Mustang Island
Block 103, processes natural gas from Pioneer Natural Resources Company's Falcon
Field located in East Breaks Blocks 579 and 580 and Harrier Field located in
East Breaks Blocks 758 and 759. Pioneer has dedicated 69,120 acres of property
to this platform for the life of the reserves.

Marco Polo Platform. We have installed the Marco Polo TLP, which has 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 second quarter of 2004, was
designed and located to process oil and natural gas from Anadarko Petroleum
Corporation's Marco Polo Field located in Green Canyon Block 608. Anadarko has
dedicated 69,120 acres of property to this TLP, including the acreage underlying
their Marco Polo Field, for the life of the reserves.

16

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 is 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. Anadarko will operate
the Marco Polo TLP. The total cost of the project is expected to be $232
million, or approximately $116 million for our share. As of December 31, 2003,
Deepwater Gateway has spent approximately $225 million on this TLP. Deepwater
Gateway handed over operations of the Marco Polo TLP to Anadarko in the first
quarter of 2004. Anadarko has installed a work-over rig and has commenced the
completion of the Marco Polo wells.

Deepwater Gateway has a $155 million project finance loan to fund a
substantial portion of the cost to construct the Marco Polo TLP and related
facilities. See Item 8, Financial Statements and Supplementary Data, Note 6, for
additional discussion of the project finance loan.

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 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.

NON-SEGMENT ACTIVITY

Currently, we own interests in four 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.

17

Producing Properties

The following table sets forth information regarding our producing
properties as of December 31, 2003.

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

(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 plugged and abandoned this well in 2003.

(2) 25 percent of our 100 percent working interest in Viosca Knoll Block 817/861
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, 2003, the unpaid portion of the
production payment obligation totaled $9.1 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, 2003. 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, 2003, 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.

18

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.

(2) The components of average 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 non-segment results, to subsidiaries included in our
platforms segment. These platform access fees are eliminated in our
consolidated financial statements. The contracts for the platform access
fees that were paid by our oil and natural gas subsidiary expired in 2002.
For the years 2002 and 2001, these platform access fees were approximately
$6.8 million and $10 million. On a consolidated basis our average realized
costs per unit of production 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.

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;

- using and restoring the surface of properties upon which wells are
drilled; and

- plugging and abandoning of wells.

19

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 United States 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 federal
and state safety and environmental 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 Part II, Item 8, Financial Statements and
Supplementary Data, Note 11.

SPECIFIC REGULATIONS

Pipelines. Several federal and state environmental statutes and
regulations may pertain specifically to the operations of our pipelines. Among
these, the Hazardous Materials Transportation Act regulates materials capable of
posing an unreasonable risk to health, safety and property when transported in
commerce, and 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
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.

20

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 other federal and 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 other
federal and state statutes and regulations, which 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 $3 million in aggregate for the
years 2004 through 2008 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 our general partner has any employees. Our administrative
and operating personnel are provided by subsidiaries of El Paso Corporation
through a general and administrative services agreement with our general
partner. 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.

21

AVAILABLE INFORMATION

Our website is http://www.gulfterra.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.

22

ITEM 2. PROPERTIES

A description of our properties is included in Item 1, Business, and is
incorporated herein by reference.

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, Arizona Gas Storage, L.L.C. and GulfTerra
Arizona Gas, L.L.C.) are pledged as collateral under our credit facility. In
addition, our Poseidon, Cameron Highway and Deepwater Gateway joint ventures
currently have credit arrangements under which substantially all of their assets
are pledged. For a discussion of our and our joint ventures' credit
arrangements, see Item 8, Financial Statements and Supplementary Data, Note 6.

ITEM 3. LEGAL PROCEEDINGS

See Part II, Item 8, Financial Statements and Supplementary Data, Note 11.

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

None.

23

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 "GTM". As of March 10, 2004, we had 738 unitholders of record and the
closing price on the NYSE for common units was $41.09 per unit.

The following table reflects the quarterly high and low sales prices for
our 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 2004, we declared a quarterly distribution of $0.71 per common
unit which was paid on February 15, 2004, to unitholders of record on January
30, 2004. Our quarterly distribution rate represents an annual distribution rate
of $2.84 per unit, up $0.14 compared to the annual rate of $2.70 declared in the
fourth quarter of 2002.

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,
2003, we paid $168.2 million in distributions to our common unitholders,
including El Paso Corporation, and $70.2 million to our general partner related
to incentive distributions as well as our general partner's one percent income
distribution.

We issued Series C units to a subsidiary of El Paso Corporation in
connection with our November 2002 San Juan assets acquisition. See 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.

24

RECENT OFFERINGS OF COMMON UNITS

During 2003, we issued the following common units in public offerings:

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

(1) Offering includes 80 Series F convertible units, which are described below.

In addition to our public offerings of common units, in October 2003 we
sold 3,000,000 common units privately (in an exempt transaction under Section
4(2) of the Securities Act of 1933 as a transaction not involving a public
offering) to Goldman Sachs in connection with their purchase of a 9.9 percent
membership interest in our general partner (which interest was repurchased in
connection with the signing of the Enterprise merger agreement). We used the net
proceeds of $111.5 million from that private sale to temporarily reduce amounts
outstanding under our revolving credit facility and, in December 2003, to redeem
a portion of our outstanding senior subordinated notes.

In connection with the offerings in 2003, our general partner contributed
to us approximately $2.0 million of our Series B preference units and cash of
$3.1 million in order to maintain its one percent general partner interest.

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. In
October 2001, we redeemed 44,608 of the Series B preference units for their
liquidation value of $50 million, including accrued distributions of
approximately $5.4 million, bringing the total number of units outstanding to
125,392. In October 2003, we redeemed all 123,865 of our remaining outstanding
Series B preference units for $156 million, a 7 percent discount from their
liquidation value of $167 million. For this redemption, we used borrowings under
our revolving credit facility. We reflected the discount as an increase to the
common units capital, Series C units capital and to our general partner's
capital accounts.

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 has
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. The
holder of the Series C units has thus far not requested a vote to convert the
Series C units into common units. As part of the proposed merger with
Enterprise, immediately prior to the closing of the merger, Enterprise will
purchase from a subsidiary of El Paso Corporation all of our outstanding Series
C units. These units will not be converted to Enterprise common units in the
merger but

25

rather will remain limited partnership interests in GulfTerra after the closing
of the merger transaction and, as such, will lose their GulfTerra common unit
conversion and distribution rights.

SERIES F CONVERTIBLE UNITS

In May 2003, we issued 1,118,881 common units and 80 Series F convertible
units in a registered offering to a large institutional investor for
approximately $38.3 million net of offering costs. Our Series F convertible
units are not listed on any securities exchange or market. Each Series F
convertible unit is comprised of two separate detachable units -- a Series F1
convertible unit and a Series F2 convertible unit -- that have identical terms
except for vesting and termination dates and the number of underlying common
units into which they may be converted. The Series F1 units are convertible into
up to $80 million of common units anytime after August 12, 2003, and until the
date we merge with Enterprise (subject to other defined extension rights). The
Series F2 units are convertible into up to $40 million of common units. The
Series F2 units terminate on March 30, 2005 (subject to defined extension
rights). The price at which the Series F convertible units may be converted to
common units is equal to the lesser of (i) the prevailing price (as defined
below), if the prevailing price is equal to or greater than $35.75, or (ii) the
prevailing price minus the product of 50 percent of the positive difference, if
any, of $35.75 minus the prevailing price. The prevailing price is equal to the
lesser of (i) the average closing price of our common units for the 60 business
days ending on and including the fourth business day prior to our receiving
notice from the holder of the Series F convertible units of their intent to
convert them into common units; (ii) the average closing price of our common
units for the first seven business days of the 60 day period included in (i);
or(iii) the average closing price of our common units for the last seven days of
the 60 day period included in (i). The price at which the Series F convertible
units could have been converted to common units assuming we had received a
conversion notice on December 31, 2003 and March 2, 2004, was $40.38 and $39.40.
The Series F convertible units may be converted into a maximum of 8,329,679
common units. Holders of Series F convertible units are not entitled to vote or
receive distributions. The $4.1 million value associated with the Series F
convertible units is included in partners' capital as a component of common
units capital.

In August 2003, we amended the terms of the Series F convertible units to
permit the holder to elect a "cashless" exercise -- that is, an exercise where
the holder gives up common units with a value equal to the exercise price rather
than paying the exercise price in cash. If the holder so elects, we have the
option to settle the net position by issuing common units or, if the settlement
price per unit is above $26.00 per unit, paying the holder an amount of cash
equal to the market price of the net number of units. These amendments had no
effect on the classification of the Series F convertible units on the balance
sheet at December 31, 2003.

In the first quarter of 2004, 45 Series F1 convertible units were converted
into 1,146,418 common units, for which the holder of the convertible units paid
us $45 million.

Any Series F convertible units outstanding at the merger date will be
converted into rights to receive Enterprise common units, subject to
restrictions governing the Series F units. The number of Enterprise common units
and the price per unit at conversion will be adjusted based on the 1.81 exchange
ratio.

EQUITY COMPENSATION PLANS

Refer to the information included in Part III, Item 12, Security Ownership
of Certain Beneficial Owners and Management, regarding securities authorized for
issuance under equity compensation plans.

26

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;
- GTM Texas in February 2001;
- the Petal and Hattiesburg natural gas storage facilities in August 2000;
- GulfTerra Alabama Intrastate 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 assets and entities are included in our results
prospectively from the purchase date. In addition, operating results and
financial position reflect the sale of our direct and indirect 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 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 decrease in 2003 reflects:
- Repayment of our $160 million GulfTerra Holding term credit facility; and
- Repayment of our $237.5 million senior secured acquisition term loan.

These decreases in 2003 are offset by a increase in the term loan portion of
our credit facility from $160 million to $300 million.

27

(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.

(7)The increase in 2003 reflects:
- the issuance of our $250 million senior notes in July 2003;
- the issuance of our $300 million senior subordinated notes in March 2003;
and
- the redemption of a portion of our outstanding senior subordinated notes
in December 2003.

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.

(8)Reflects the issuance of:
- 7.8 million common units in October 2003;
- 0.5 million common units in August 2003;
- 1.2 million common units in June 2003;
- 1.1 million common units in May 2003;
- 3.5 million common units in April 2003;
- 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 October 2003, we redeemed all 123,865 of our remaining outstanding Series
B preference units for $156 million, a 7 percent discount from their
liquidation value of $167 million. Also, we redeemed $50 million in
liquidation value of our Series B preference units in October 2001.

28

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

Our Management's Discussion and Analysis includes forward-looking
statements that are subject to risks and uncertainties. Actual results may
differ substantially from the statements we make in this section due to a number
of factors, including those discussed beginning on page 56.

GENERAL

Our objective is to operate as a growth-oriented 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. 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.

MERGER WITH ENTERPRISE

To further our business strategy, we executed definitive agreements with
Enterprise and El Paso Corporation, on December 15, 2003, to merge Enterprise
and GulfTerra to form one of the largest publicly traded MLPs with an enterprise
value of approximately $13 billion as of December 15, 2003. Subject to any
divestitures required under the Hart-Scott-Rodino Act, the combined partnership
will own or have interests in:

- 17,000 miles of natural gas pipelines;

- 13,000 miles of NGL and petrochemical pipelines;

- 340 miles of large capacity crude oil pipelines in the Gulf of Mexico;

- 164 MMBbls of NGL storage capacity;

- 23 Bcf of natural gas storage capacity;

- Seven offshore Gulf of Mexico hub platforms;

- NGL import and export terminals on the Houston Ship Channel;

- 19 NGL fractionation plants with a net capacity of approximately 650
MMBbls/d; and

- 24 natural gas processing plants with a net capacity of 6.0 Bcf/d.

The general partner of the combined partnership will be jointly owned by
affiliates of El Paso Corporation and privately-held Enterprise Products
Company, with each owning a 50-percent interest.

The combined partnership, which will retain the name Enterprise Products
Partners L.P., will serve the largest producing basins of natural gas, crude oil
and NGLs in the U.S., including the Gulf of Mexico, Rocky Mountains, San Juan
Basin, Permian Basin, South Texas, East Texas, Mid-Continent and Louisiana Gulf
Coast basins and, through connections with third-party pipelines, Canada's
western sedimentary basin. The partnership will also serve the largest consuming
regions for natural gas, crude oil and NGLs on the U.S. Gulf Coast.

The definitive agreements include three transactions. In the initial
transaction, completed and funded on December 15, 2003, a subsidiary of
Enterprise acquired a 50-percent, limited voting interest in our general
partner, GulfTerra Energy Company, L.L.C., for $425 million in cash. Prior to
the closing of this transaction, El Paso Corporation reacquired the 9.9-percent
ownership interest in our general partner held by Goldman Sachs. As a result of
this initial step, our general partner is owned 50 percent by a subsidiary of El
Paso Corporation and 50 percent by a subsidiary of Enterprise. El Paso
Corporation's subsidiary continues
29

to serve as the managing member of our general partner, and the Enterprise
affiliate member's rights are limited to protective consent rights on certain
transactions affecting us or our general partner.

In the second transaction, which will occur immediately prior to the
merger, El Paso Corporation will contribute its 50-percent ownership interest in
our general partner to Enterprise Products GP, LLC, the current general partner
of Enterprise and continuing general partner of the merged partnerships. In
exchange, El Paso Corporation will receive a 50-percent interest in Enterprise's
general partner. The remaining 50 percent of the Enterprise general partner will
continue to be owned by affiliates of Enterprise Products Company. The
Enterprise general partner will then contribute this 50-percent ownership
interest in our general partner to Enterprise for no consideration. In addition,
Enterprise will pay El Paso Corporation $500 million in cash for approximately
13.8 million units, which include 2.9 million of our common units and all of our
Series C units.

In the final transaction, we will merge with a wholly-owned subsidiary of
Enterprise, with us surviving the merger as a wholly-owned subsidiary of
Enterprise. Under the terms of the merger agreement, our unitholders will
receive 1.81 Enterprise common units for each GulfTerra common unit, which
represents a premium of approximately 2.2 percent based on the closing prices of
their respective common units on December 12, 2003, the last trading day before
the agreements were signed. The remaining approximately 7.5 million GulfTerra
common units owned by El Paso Corporation will be exchanged for Enterprise
common units based on the 1.81 exchange ratio. The GulfTerra common units and
Series C units acquired by Enterprise for cash will not convert into Enterprise
common units and, after the closing of the merger, will lose all distribution
rights. After the merger, El Paso Corporation will own approximately 14.9
million common units of Enterprise.

The completion of the merger is subject to the approval of the unitholders
of both Enterprise and GulfTerra along with customary regulatory approvals,
including that under the Hart-Scott-Rodino Antitrust Improvements Act.
Completion of the merger is expected to occur during the second half of 2004.

In connection with the closing of the merger, Enterprise will acquire nine
natural gas processing plants from El Paso Corporation for $150 million in cash.
These plants, located in South Texas, have historically been associated with and
are integral to our Texas intrastate natural gas pipeline and NGL fractionation
and pipeline systems.

Under the terms of the merger agreement, the board of directors of the
general partner of Enterprise will consist of ten directors, of which five will
be designated by Enterprise Products Company and five will be designated by El
Paso Corporation. Six of the directors (three of those designated by Enterprise
Products Company and three of those designated by El Paso Corporation) will be
independent directors meeting the requirements established by the NYSE. Two of
the directors designated by Enterprise initially will be Dan L. Duncan, the
current Chairman of Enterprise's general partner, and O.S. Andras, the current
Chief Executive Officer of Enterprise's general partner. Two of the directors
designated by El Paso Corporation initially will be Robert G. Phillips, our
general partner's current Chairman and Chief Executive Officer, and D. Dwight
Scott, Executive Vice President and Chief Financial Officer of El Paso
Corporation. Following the merger, Mr. Duncan will be Chairman, Mr. Andras will
be Vice Chairman and Chief Executive Officer and Mr. Phillips will be President
and Chief Operating Officer of Enterprise's general partner. If the approval of
any matter that is before the board is equally split for and against, Mr. Duncan
will cast the deciding vote.

Because the closing of the merger will be a change of control, and thus a
default, under our credit facility, we will either repay or amend that facility
prior to the closing. In addition, because the merger closing will constitute a
change of control under our indentures, we will be required to offer to
repurchase our outstanding senior subordinated notes (and possibly our senior
notes) at 101 percent of their principal amount after the closing. In
coordination with Enterprise, we are evaluating alternative financing plans in
preparation for the close of the merger. We and Enterprise can agree on the date
of the merger closing after the receipt of all necessary approvals. We do not
intend to close until appropriate financing is in place.

30

Under the merger agreement, we are required to generally conduct our
business in the ordinary course consistent with past practice. In addition, we
may not take any of the following actions without Enterprise's consent:

- issue or sell any equity securities other than (1) pursuant to our
employee benefit plans, options, and Series F convertible units and (2)
up to $100 million of common units;

- declare or pay distributions in excess of $0.71 per common unit (unless
required by our partnership agreement);

- acquire assets for consideration in excess of $50 million or $100 million
in the aggregate;

- sell assets with a fair market value in excess of $10 million or $25
million in the aggregate;

- make investments, other than required by joint venture agreements, in
excess of $25 million in aggregate;

- incur additional indebtedness other than (1) ordinary course borrowings
under our revolving credit facility and (2) up to $100 million in
principal amount of additional indebtedness with a maturity of no more
than three years and no repayment penalty; and

- make capital expenditures in excess of $5 million or $25 million in the
aggregate other than (1) as required on an emergency basis and (2) those
planned expenditures previously disclosed to Enterprise.

If the merger agreement is terminated and (1) a business transaction
between us and a third party that conflicts with the merger was proposed and
certain other conditions were met or (2) we materially and willfully violated
our agreement not to solicit transactions that conflict with the merger, then we
will be required to pay Enterprise a termination fee of $112 million. If the
merger agreement is terminated because our unitholders did not approve the
merger and either (1) a possible business transaction involving us but not
involving Enterprise and conflicting with the merger was publicly proposed and
our board of directors publicly and timely reaffirmed its recommendations of the
Enterprise merger or (2) no such possible business transaction was publicly
announced, then we will be required to pay Enterprise a termination fee of $15
million. Enterprise is subject to similar termination fee requirements.

CAPITAL PROJECTS

During 2003, we integrated our 2002 asset acquisitions of the EPN Holding
and the San Juan assets. The assets acquired in these acquisitions performed
well in 2003 and are now the core of our business. They provide us the stable
cash flow to use, along with borrowings under credit facilities and other debt
and equity transactions, to fund our midstream projects underway in the Gulf of
Mexico, which have gross estimated capital costs of $862 million, including 426
miles of oil pipelines and 151 miles of natural gas pipelines.

Cameron Highway. We are constructing the $458 million, 390-mile Cameron
Highway oil pipeline with capacity of 500 MBbls/d, which is expected to be in
service by the fourth 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 June 2003, we formed Cameron Highway Oil Pipeline Company and
contributed to it the $458 million Cameron Highway oil pipeline system
construction project. Cameron Highway is responsible for building and operating
the pipeline, which is scheduled for completion during the fourth quarter of
2004. We entered into producer agreements with three major anchor producers, BP
Exploration & Production Company, BHP Billiton Petroleum (Deepwater), Inc. and
Union Oil Company of California, which agreements were assigned to and assumed
by Cameron Highway. The producer agreements require construction of the 390-mile
Cameron Highway oil pipeline.

In July 2003, we sold a 50 percent interest in Cameron Highway to Valero
for $86 million, forming a joint venture with Valero. Valero paid us
approximately $70 million at closing, including $51 million representing
31

50 percent of the capital investment expended through that date for the pipeline
project, and we recognized $19 million as a gain from the sale of long-lived
assets. In addition, Valero will pay us $5 million once the system is completed
and an additional $11 million by the end of 2006. We expect to reflect these
additional amounts as gains from the sale of long-lived assets in the periods
they are received. In connection with the formation of the Cameron Highway joint
venture, Valero agreed to pay their proportionate share of the pipeline
construction costs that exceed Cameron Highway's capital resources, including
the initial equity contributions and proceeds from Cameron Highway's project
loan facility.

The Cameron Highway oil pipeline system project is expected to be funded
with $169 million equity through capital contributions from us and Valero, the
two Cameron Highway partners, which contributions have already been made and the
remainder from borrowings by Cameron Highway under its $325 million project loan
facility, consisting of a $225 million construction loan and $100 million of
senior secured notes. As of December 31, 2003, Cameron Highway has spent
approximately $256 million related to this pipeline, which is in the
construction stage. We and Valero are obligated to make additional capital
contributions to Cameron Highway if and to the extent that the construction
costs for the pipeline exceed Cameron Highway's capital resources, including the
initial equity contributions and proceeds from Cameron Highway's project loan
facility.

Marco Polo Platform. We have installed the Marco Polo TLP, which has 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 second quarter of 2004, was
designed and located to process oil and natural gas from Anadarko Petroleum
Corporation's Marco Polo Field located in Green Canyon Block 608. Anadarko has
dedicated 69,120 acres of property to this TLP, including the acreage underlying
their Marco Polo Field, 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 is
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. Anadarko will operate the Marco Polo
TLP. The total cost of the project is expected to be $232 million, or
approximately $116 million for our share. As of December 31, 2003, Deepwater
Gateway has spent approximately $225 million on this TLP. Deepwater Gateway
handed over operations of the Marco Polo TLP to Anadarko in the first quarter of
2004. Anadarko has installed a work-over rig and has commenced the completion of
the Marco Polo wells.

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, 2003, Deepwater Gateway had $155 million outstanding under the
project finance loan and had not paid us, our joint venture partner or any of
our subsidiaries any distributions.

As of December 31, 2003, we have contributed $33 million, as our 50 percent
share, to Deepwater Gateway, which amount satisfies our initial equity 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 and Deepwater Gateway's members' contingent equity
obligations (of which our share is $14 million). 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
Marco Polo Oil and Gas Pipelines. We are constructing and will own 100 percent
of a 36-mile, 14-inch oil pipeline and a 75-mile, 18 and 20-inch natural gas
gathering system to support the Marco Polo TLP. The

32

natural gas gathering system, 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 gathering system in Green Canyon Block 237. We
intend to integrate the Marco Polo natural gas gathering system and the Typhoon
natural gas gathering system. The oil pipeline will gather oil from the Marco
Polo platform into 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 mid-year 2004, and are expected to cost a total of $106
million to construct. We incurred higher costs than originally anticipated as
the result of installation timing conflicts between the Marco Polo TLP
installation and the Marco Polo gas pipeline installation and construction down
time as the result of weather related delays and strong sea currents. As of
December 31, 2003, we have spent approximately $72.7 million on these pipelines,
which are in the development stage. Additionally, we received 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 of
increased volumes they anticipate receiving on their facilities as a result of
our construction of the natural gas pipeline. We expect to fund the remaining
project costs through internally generated funds and borrowings under our credit
facility.

Phoenix Gathering System. We are constructing and will own 100 percent of
a new $66 million 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 subsidiaries of Kerr-McGee Corporation and
Devon Energy, Inc., which each hold a 50-percent working interest in the Red
Hawk Field. Kerr-McGee and Devon 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 platform and connect to the ANR Patterson
Offshore Pipeline system at Vermillion Block 397. We plan to place the new
pipeline in service mid-year of 2004. As of December 31, 2003, we have spent
approximately $51.7 million related to this pipeline, which is in the
construction stage. We expect to receive contributions in aid of construction
from ANR Pipeline Company, a subsidiary of El Paso Corporation, of $6.1 million,
of which $3.0 million has been collected, for the benefits of increased volumes
they expect to transport on their pipeline as a result of our construction of
this pipeline. We expect to fund the remaining project costs through internally
generated funds and borrowings under our credit facility.

San Juan Optimization Project. In May 2003, we commenced a $43 million
project relating to our San Juan Basin assets. The project is expected to be
completed in stages through 2006. The project is expected to result in increased
capacity of up to 130 MMcf/d on the San Juan gathering system and increased
market opportunities through a new interconnect at the tailgate of our Chaco
plant. As of December 31, 2003, we have spent approximately $1.8 million related
to this project. We expect to fund the remaining project costs through
internally generated funds and borrowings under our credit facility.

Front Runner Oil Pipeline. In September 2003, we announced that Poseidon,
our 36 percent owned joint venture, entered into an agreement for the purchase
and sale of crude oil from the Front Runner Field. Poseidon will construct, own
and operate the $28 million project, which will connect the Front Runner
platform with Poseidon's existing system at Ship Shoal Block 332. The new
36-mile, 14-inch pipeline is expected to be operational by the third quarter of
2004 and have a capacity of 65 MBbls/d. As Poseidon expects to fund Front
Runner's capital expenditures from its operating cash flow and from its
revolving credit facility, we do not expect to receive distributions from
Poseidon until the Front Runner pipeline is completed.

Petal Expansion Project. In September 2003, we entered into a nonbinding
letter of intent with Southern Natural Gas Company, a subsidiary of El Paso
Corporation, regarding the proposed development and sale of a natural gas
storage cavern and the proposed sale of an undivided interest in a pipeline and
other facilities related to that natural gas storage cavern. The new storage
cavern would be located at our storage complex near Hattiesburg, Mississippi. If
Southern Natural Gas determines that there is sufficient market interest, it
would purchase the land and mineral rights related to the proposed storage
cavern and would pay our costs to construct the storage cavern and related
facilities. Upon completion of the storage cavern, Southern Natural Gas would
acquire an undivided interest in our Petal pipeline connected to the storage

33

cavern. We would also enter into an arrangement with Southern Natural Gas under
which we would operate the storage cavern and pipeline on its behalf. Southern
Natural Gas is holding an open season for the space.

Before we consummate this transaction, and enter into definitive
transaction documents, the transaction must be recommended by the audit and
conflicts committee of our general partner's board of directors, which committee
consists solely of directors meeting the independent director requirements
established by the NYSE and the Sarbanes-Oxley Act and then approved by our
general partner's full board of directors.

We are also considering converting our existing brine well at our propane
storage caverns in Hattiesburg to natural gas service. This conversion would
cost approximately $16 million and would create a new 1.8 Bcf working natural
gas cavern that would be integrated into our Petal storage complex. We are
currently negotiating with customers for the full 1.8 Bcf of capacity and
expect, subject to final regulatory approval, to have the cavern in service
during the fourth quarter of 2004.

GENERAL PARTNER RELATIONSHIP

In May 2003, GulfTerra Energy Company, L.L.C., a Delaware limited liability
company and a wholly owned subsidiary of El Paso Corporation, became our general
partner by acquiring our general partner interest from our previous general
partner, which was also a wholly owned subsidiary of El Paso Corporation.

Goldman Sachs

In October 2003, Goldman Sachs made a $200 million investment in us and our
general partner by acquiring a 9.9 percent membership interest in our general
partner from El Paso Corporation for $88 million and 3,000,000 common units from
us for $112 million. Adding a co-owner of our general partner was one of the
major steps of our Independence Initiatives, which we identified as necessary
elements of functioning and being evaluated by the capital markets, as a
stand-alone, independent operating company.

In December 2003, El Paso Corporation reacquired Goldman Sachs' 9.9 percent
interest in our general partner and then sold a 50 percent interest in our
general partner to a subsidiary of Enterprise, as discussed earlier. Goldman
Sachs no longer owns any interest in our general partner.

Enterprise

In December 2003, a subsidiary of Enterprise purchased a 50 percent
interest in our general partner. Enterprise is a leading North American
midstream energy company that provides a wide range of services to producers and
consumers of natural gas and NGLs. A subsidiary of Enterprise:

- owns 50 percent of our general partner. Enterprise subsidiary's rights
are limited to protective consent rights on specified material
transactions affecting us or our general partner and the rights and
preferences associated with the membership interest in the general
partner owned by the Enterprise subsidiary.

- is a customer of ours. However, historically our transactions with
Enterprise have been immaterial.

El Paso Corporation

In December 2003, El Paso Corporation sold a 50 percent interest in our
general partner to Enterprise. El Paso Corporation, a 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 50 percent, and is the managing member, of our general partner.
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 under our
general and administrative services agreement. The fees we incur for
services under this agreement with El Paso Corporation reflect the
benefit from El Paso Corporation's ability to utilize their economies of
scale to negotiate service levels at favorable costs. We will continue
to obtain these services from El Paso Corporation; however; if these
services were to end, our expenditures may increase as we may
34

not be able to obtain the same level of services at comparable costs. We
also 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 stake-holder in us -- as of March 10, 2004, it owns
approximately 17.3 percent, or 10,310,045, of our common units
(decreased from 26.5 percent as a result of our common unit offerings
during 2003, its public sale of 590,000 common units in October 2003 and
its sale of 772,400 common units to Goldman Sachs in connection with its
December 2003 repurchase of Goldman Sachs' 9.9 percent interest in our
general partner), all 10,937,500 of our Series C units, which we issued
in November 2002 for $350 million, and 50 percent of our general
partner. 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. In
July 2003, we filed a registration statement on Form S-3 to register for
resale 2,000,000 of the common units owned by El Paso Corporation or its
subsidiaries. Under this registration statement, an El Paso Corporation
subsidiary sold 590,000 of its common units in October 2003.

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

Exchange Transactions With El Paso Corporation

In connection with our November 2002 San Juan assets acquisition, El Paso
Corporation retained the obligation to repurchase the Chaco plant from us for
$77 million in October 2021. In October 2003, we released El Paso Corporation
from that obligation and El Paso Corporation contributed specified
communications assets and other rights to us. The communications assets we
received are used in the operation of our pipeline systems.

As a result of the October 2003 exchange, we revised our estimate for the
depreciable life of the Chaco Plant from 19 to 30 years, the estimated remaining
useful life of the Chaco plant. Depreciation expense will decrease approximately
$0.5 million and $2.3 million on a quarter and annual basis.

In October 2003, we redeemed all 123,865 of our remaining outstanding
Series B preference units for $156 million, a 7 percent discount from their
liquidation value of $167 million. For this redemption, we used borrowings under
our revolving credit facility. We reflected the discount as an increase to the
common units capital, Series C units capital and to our general partner capital
accounts.

In accordance with our procedures for evaluating and valuing material
transactions with El Paso Corporation, our general partner's Audit and Conflicts
Committee engaged an independent financial advisor to provide a fairness opinion
related to transactions with Goldman Sachs, except for the purchase from El Paso
Corporation of the 9.9 percent general partner interest, the asset exchange with
El Paso Corporation, and the redemption of Series B Preference Units. Based on
this opinion, the Audit and Conflicts Committee and the full board of directors
approved these transactions taken as a whole.

OTHER

We have continued to improve our corporate governance model, which we
believe currently meets the standards established by the Securities and Exchange
Commission (SEC) and NYSE. During the first quarter of 2003, we 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, which we refer to
as Independence Initiatives. During 2003, we were largely successful in
implementing these initiatives, as well as implementing what we believed to be
the best practices in corporate governance. We added an additional independent
director to our board of directors, bringing the number of independent directors
to four of the six-member board. Further, we established a governance and
compensation committee of our board of directors, consisting solely of
independent directors, which is responsible for establishing performance
measures and making recommendations to El Paso Corporation concerning
compensation of its employees performing duties for us. Finally, our general

35

partner received third party investments (first from Goldman Sachs and then from
Enterprise), which made our general partner's decision making process more
independent from El Paso Corporation.

LIQUIDITY AND CAPITAL RESOURCES

Our principal requirements for cash, other than our routine operating
costs, are for capital expenditures, debt service, business acquisitions and
distributions to our partners. We plan to fund our short-term cash needs,
including operating costs, maintenance capital expenditures and cash
distributions to our partners, from cash generated from our operating activities
and borrowings under our credit facility. Capital expenditures we expect to
benefit us over longer time periods, including our organic growth projects and
business acquisitions, we plan to fund through a variety of sources (either
separately or in combination), which include issuing additional common units,
borrowing under commercial bank credit facilities, issuing public or private
placement debt and other financing transactions. We plan to fund our debt
service requirements through a combination of refinancing arrangements and cash
generated from our operating activities. Our merger agreement with Enterprise
limits our ability to raise additional capital prior to the closing of the
merger without Enterprise's approval; however, we believe that these limitations
will not affect our liquidity.

The ability to execute our growth strategy and complete our projects is
dependent upon our access to the capital necessary to fund the projects and
acquisitions. Our success with capital raising efforts, including the formation
of joint ventures to share costs and risks, continues to 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 discussed below, we may adjust the timing and amounts of projected
expenditures as necessary to adapt to changes in the capital markets.

CAPITAL RESOURCES

Our announced strategy for 2003 was to continue to finance or re-finance
our growth with 50 percent equity to ensure a sound capital structure. During
2003, we have raised net proceeds of approximately $387.5 million through public
offerings of 11,026,109 common units, successfully accomplishing part of our
strategy for 2003. We used the net proceeds from our public offerings of common
units to temporarily reduce amounts outstanding under our revolving credit
facility and for general partnership purposes. The following table provides
additional detail regarding our public offerings since January 2003:

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

(1) Offering includes 80 Series F convertible units, which are described below.

In addition to our public offerings of common units, in October 2003 we
sold 3,000,000 common units privately to Goldman Sachs in connection with their
purchase of a 9.9 percent membership interest in our general partner. We used
the net proceeds of $111.5 million from that private sale to temporarily reduce
indebtedness under our revolving credit facility and, in December 2003, to
redeem a portion of our outstanding senior subordinated notes. See below in this
section under "Indebtedness and Other Obligations," for a discussion of the
redemption of a portion of our senior subordinated notes.

We expect to use the proceeds we receive from any additional capital we
raise through the issuance of additional common units to temporarily reduce
amounts outstanding under our credit facility, to finance growth opportunities
and for general partnership purposes. Our ability to raise additional capital
may be negatively affected by many factors, including limitations imposed by our
merger agreement with Enterprise.

36

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. In connection with our 2003
public offerings of common units through September 30, 2003, our general
partner, in lieu of a cash contribution, contributed to us, and we retired,
1,527 Series B preference units with liquidation value of approximately $2.0
million, including accrued distributions of approximately $0.5 million, to
maintain its one percent general partner interest. In October 2003, we redeemed
all of our remaining outstanding Series B preference units.

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 has 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 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. The holder of the Series C units
has thus far not requested a vote to convert the Series C units into common
units. As part of the proposed merger with Enterprise, in the second
transaction, which will occur immediately prior to the merger, Enterprise will
purchase from a subsidiary of El Paso Corporation all of our outstanding Series
C units. These units will not be converted to Enterprise common units in the
merger but rather will remain limited partnership interests in GulfTerra after
the merger and, as such interest, will lose their GulfTerra common unit
conversion and distribution rights.

SERIES F CONVERTIBLE UNITS

In connection with our public offering of 1,118,881 common units in May
2003, we issued 80 Series F convertible units. Each Series F convertible unit is
comprised of two separate detachable units -- a Series F1 convertible unit and a
Series F2 convertible unit -- that have identical terms except for vesting and
termination times and the number of underlying common units into which they may
be converted. The Series F1 units are convertible into up to $80 million of
common units anytime after August 12, 2003, and until the date we merge with
Enterprise (subject to other defined extension rights). The Series F2 units are
convertible into up to $40 million of common units. The Series F2 units
terminate on March 30, 2005 (subject to defined extension rights). The price at
which the Series F convertible units may be converted to common units equal to
the lesser (i) of the prevailing price (as defined below), if the prevailing
price is equal to or greater than $35.75, or (ii) the prevailing price minus the
product of 50 percent of the positive difference, if any, of $35.75 minus the
prevailing price. The prevailing price is equal to the lesser of (i) the average
closing price of our common units for the 60 business days ending on and
including the fourth business day prior to our receiving notice from the holder
of the Series F convertible units of their intent to convert them into common
units; (ii) the average closing price of our common units for the first seven
business days of the 60 day period included in (i); or (iii) the average closing
price of our common units for the last seven days of the 60 day period included
in (i). The price at which the Series F convertible units could have been
converted to common units assuming we had received a conversion notice on
December 31, 2003 and March 2, 2004, was $40.38 and $39.40. The Series F units
may be converted into a maximum of 8,329,679 common units. Holders of Series F
convertible units are not entitled to vote or receive distributions. The $4.1
million value associated with the Series F convertible units is included in
partners' capital as a component of common units capital.

37

In August 2003, we amended the terms of the Series F convertible units to
permit the holder to elect a "cashless" exercise -- that is, an exercise where
the holder gives up common units with a value equal to the exercise price rather
than paying the exercise price in cash. If the holder so elects, we have the
option to settle the net position by issuing common units or, if the settlement
price per unit is above $26.00 per unit, paying the holder an amount of cash
equal to the market price of the net number of units. These amendments had no
effect on the classification of the Series F convertible units on the balance
sheet at December 31, 2003.

In the first quarter of 2004, 45 Series F1 convertible units were converted
into 1,146,418 common units, for which the holder of the convertible units paid
us $45 million.

Any Series F convertible units outstanding at the merger date will be
converted into rights to receive Enterprise common units, subject to the
restrictions governing the Series F units. The number of Enterprise common units
and the price per unit at conversion will be adjusted based on the 1.81 exchange
ratio.

INDEBTEDNESS AND OTHER OBLIGATIONS

In March 2003, we issued $300 million in aggregate principal amount of
8 1/2% senior subordinated notes due 2010. We used the proceeds of approximately
$293.5 million, net of issuance costs, to repay all indebtedness outstanding
under our $237.5 million senior secured acquisition term loan and to temporarily
repay $55.5 million of the balance outstanding under our revolving credit
facility.

In July 2003, we issued $250 million in aggregate principal amount of
6 1/4% senior notes due 2010. We used the proceeds of approximately $245.1
million, net of issuance costs, to repay the remaining $160 million of
indebtedness under the GulfTerra Holding term credit facility and the remaining
$85.1 million to temporarily reduce amounts outstanding under our revolving
credit facility.

In July 2003, Cameron Highway Oil Pipeline Company, our 50 percent owned
joint venture that is constructing the 390-mile Cameron Highway Oil Pipeline,
entered into a $325 million project loan facility consisting of a $225 million
construction loan and $100 million of senior secured notes. At December 31,
2003, Cameron Highway had $69 million outstanding under the construction loan
and $56 million of senior secured notes outstanding.

In July 2003, to achieve a better mix of fixed rate debt and variable rate
debt, we entered into an eight-year interest rate swap agreement to provide for
a floating interest rate on $250 million out of $480 million of our 8 1/2%
senior subordinated notes due 2011. With this swap agreement, we pay the
counterparty a LIBOR based interest rate plus a spread of 4.20% (which rate was
1.55% at December 31, 2003) and receive a fixed rate of 8 1/2%. We are
accounting for this derivative as a fair value hedge under Statement of
Financial Accounting Standards (SFAS) No. 133. At December 31, 2003, the fair
value of the swap was a liability, included in non-current liabilities, of
approximately $7.4 million. The fair value of the hedged debt decreased by the
same amount.

In September 2003, we renewed our credit facility to among other things,
increase the commitment level under the revolving component from $600 million to
$700 million and extend the maturity from May 2004 to September 2006. Under the
terms of our renewed credit facility, the interest rate we are charged is
contingent upon our leverage ratio, as defined in our credit facility, and
ratings we are assigned by S&P or Moody's. The interest we are charged would
increase by 0.25% if the credit ratings on our senior secured credit facility
decrease or our leverage ratio decreases, or alternatively, would decrease by
0.25% if these ratings are increased or our leverage ratio improves.
Additionally, we pay commitment fees on the unused portion of our revolving
credit facility at rates that vary from 0.30% to 0.50%. These increases in our
credit facility costs are the only additional costs we would bear in direct
relationship to our financing contracts.

In December 2003, we refinanced the term loan portion of our credit
facility to provide greater financial flexibility by, among other things,
expanding the existing term component from $160 million to $300 million,
extending the maturity from October 2007 to December 2008, reducing the
semi-annual payments from $2.5 million to $1.5 million and reducing the interest
rate we are charged by 1.25%. We used the proceeds from the term loan to repay
the $155 million outstanding under the initial term loan and to temporarily
reduce

38

amounts outstanding under our revolving credit facility. We charged $2.8 million
to expense in December 2003 to write off unamortized debt issuance costs
associated with the initial term loan.

In December 2003, we exercised our right, under the terms of our senior
subordinated notes' indentures, to repay, at a premium, approximately $269.4
million in principal amounts of those senior subordinated notes. The indentures
provide that, within 90 days of an equity offering, we can call up to 33 percent
of the original face amount at a premium. The amount we can repay is limited to
the net proceeds of the offering. We recognized additional costs totaling $29.1
million resulting from the payment of the redemption premiums and the write-off
of unamortized debt issuance costs, premiums and discounts. We accounted for
these costs as an expense during the fourth quarter of 2003 in accordance with
the provisions of SFAS No. 145. In March 2004, we gave notice to exercise our
right, under the terms of our senior subordinated notes' indentures, to repay,
at a premium, approximately $39.1 million in principal amount of those senior
subordinated notes. The indentures provide that, within 90 days of an equity
offering, we can call up to 33 percent of the original face amount at a premium.
The amount we can repay is limited to the net proceeds of the offering. We will
recognize additional costs totaling $4.1 million resulting from the payment of
the redemption premiums and the writeoff of unamortized debt issuance costs. We
will account for these costs as an expense during the second quarter of 2004 in
accordance with the provisions of SFAS No. 145.

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

The following table presents the timing and amounts of our debt repayment
and other obligations for the years following December 31, 2003, that we believe
could affect our liquidity (in millions):

CAPITAL 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 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 acquisitions, scope changes or decisions to take
on additional partners. Our projection of expenditures for the quarters ended
December 31, September 30,

39

June 30 and March 31, 2003 as presented in our 2002 Annual Report on Form 10-K
were $55, $78, $92 and $120 million; however, our actual expenditures were
approximately $86, $39, $125 and $80 million.

The tables below depict our estimate of projects and capital maintenance
expenditures through December 31, 2004. These estimates are net of anticipated
contributions in aid of construction and contributions from joint venture
partners. We expect to be able to fund these forecasted expenditures from a
combination of operating cash flow and funds available under our revolving
credit facility and other financing arrangements. Actual results may vary from
these projections.

FORECASTED EXPENDITURES

CONSTRUCTION PROJECTS

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

(1) Includes 100 percent of costs and is not reduced for anticipated
contributions in aid of construction, project financings and contributions
from joint venture partners. We expect to receive $6.1 million of which $3.0
million has been collected from ANR Pipeline Company for our Phoenix
project. We have received $10.5 million from ANR Pipeline Company and $7.0
million from El Paso Field Services for the Marco Polo natural gas pipeline.

(2) GulfTerra expenditures are net of anticipated or received contributions in
aid of construction, project financings and contributions from joint venture
partners to the extent applicable.

(3) Forecasted expenditures increased during 2003 due to increases in gas
processing capacity (from 250 to 300 MMcf/d) and oil processing capacity
(from 100 to 120 MBbls/d), a higher builder's risk insurance cost and
weather delays.

(4) In July 2003, we sold a 50 percent interest in Cameron Highway to Valero
Energy Corporation. Part of the consideration Valero paid us at closing was
approximately $51 million, representing 50 percent of the capital investment
expended through that date.

Under the merger agreement with Enterprise, we can not make capital
expenditures, without Enterprise's consent, in excess of $5 million or $25
million in the aggregate other than (1) as required on an emergency basis and
(2) those planned expenditures previously disclosed to Enterprise. The
forecasted expenditures disclosed in the tables above were either planned
expenditures previously disclosed to Enterprise or fall within the monetary
thresholds in the merger agreement.

40

CASH FROM OPERATING ACTIVITIES

Net cash provided by operating activities was $268.2 million for the year
ended December 31, 2003, compared to $176.0 million for the same period in 2002.
The increase was primarily attributable to operating cash flows generated by our
acquisitions of 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
2003 from Poseidon.

CASH FROM INVESTING ACTIVITIES

Net cash used in investing activities was approximately $287.2 million for
the year ended December 31, 2003. Our investing activities include capital
expenditures related to the construction of the Marco Polo pipelines, the
Cameron Highway oil pipeline and the Falcon Nest fixed-leg platform. These
expenditures were partially offset by proceeds of $69.8 million from the sale of
a 50 percent interest in Cameron Highway to Valero and $8.1 million from the
sale and retirement of other assets.

CASH FROM FINANCING ACTIVITIES

Net cash provided by financing activities was approximately $13.4 million
for the year ended December 31, 2003. During 2003, our cash provided by
financing activities included the issuances of long-term debt and offerings of
common units and convertible units. Cash used in our financing activities
included repayments on our senior secured acquisition term loan long-term debt,
our revolving credit facility and other financing obligations, as well as
distributions to our partners.

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.

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 Part II, Item 8, Financial Statements and
Supplementary Data, Note 15. For the past three years, inflation has not had a
material effect on any of our financial results.

41

SEGMENT RESULTS

We use performance cash flows (which we formerly referred to as EBITDA) to
evaluate the performance of our segments, determine how resources will be
allocated and develop strategic plans. We define performance cash flows as
earnings before interest, income taxes, depreciation and amortization and other
adjustments. Historically our lenders and equity investors have viewed our
performance cash flows measure as an indication of our ability to generate
sufficient cash to meet debt obligations or to pay distributions. We believe
that there has been a shift in investors' evaluation regarding investments in
MLPs and they now put as much focus on the performance of an MLP investment as
they do its ability to pay distributions. For that reason, we disclose
performance cash flows as a measure of our segment's performance. A
reconciliation of this measure to net income for our consolidated results is as
follows:

NATURAL GAS PIPELINES AND PLANTS

The Natural gas pipelines and plants segment includes the San Juan
gathering system and related assets, the Permian Basin System, the Texas
Intrastate system, the GulfTerra Alabama Intrastate system, the Viosca Knoll
Gathering System, the HIOS System, the East Breaks System, the Falcon Gas
Pipeline, the Typhoon Gas Pipeline, the Chaco cryogenic natural gas processing
plant and the Indian Basin processing and treating facility. The natural gas
gathering and transportation pipelines and related assets 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. GulfTerra Alabama Intrastate 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.

42

In our natural gas pipelines and plants segment, we utilize derivative
financial instruments to manage a portion of our exposure to movements in
commodity prices. For a further discussion, see Part II, Item 8, Financial
Statements and Supplementary Data, Note 12.

The following table presents performance cash flows 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) Earnings (loss) from unconsolidated affiliates for the years ended December
31, 2003, 2002, and 2001, was $2,377 thousand, $194 thousand and ($9,761)
thousand.

(2) We purchased the Texas Intrastate assets, and the Carlsbad and Waha systems,
which are included in the Permian Basin gathering systems, in April 2002.

(3) We purchased the San Juan gathering system, the remaining interest in the
Chaco processing plant and the Typhoon natural gas pipeline in November
2002.

(4) The Falcon Nest pipeline was placed in service in March 2003.

We provide natural gas gathering and transportation services for a fee.
Agreements with some customers of our pipelines require that we purchase natural
gas from producers at the wellhead for an index price less an amount that
compensates us for gathering services, after which we sell the natural gas into
the open market at points on our system at the same index price. Accordingly,
under these agreements, our operating revenues and costs of natural gas and
other products are impacted equally by changes in energy commodity prices; thus,
our margin for these agreements reflects only the fee we received for gathering
services. At our Indian Basin processing facility, our revenues reflect the
gross sales of NGLs we retain as a processing fee and the NGLs purchased from
other producers under the marketing provisions of their contracts. Included in
our cost of natural gas and other products is the payment to the producers for
the natural gas liquids we marketed on their behalf. For these reasons, we feel
that gross margin (revenue less cost of natural gas and other products) provides
a more accurate and meaningful basis for analyzing operating results for this
segment. Revenues at our Chaco processing facility are representative of our
processing fee since the NGLs purchased from the producers at this facility is
minimal.
43

During the latter half of 2002, we experienced a significant unfavorable
variance between the fuel usage on HIOS and the fuel collected from our
customers for our use. We believe a series of events may have contributed to
this variance, including two major storms that hit the Gulf Coast region (and
these assets) in late September and early October of 2002. As of December 31,
2003, we had recorded fuel differences of approximately $8.2 million, which is
included in other non-current assets. We are currently in discussions with the
FERC as well as our customers regarding the potential collection of some or all
of the fuel differences. At this time we are not able to determine what amount,
if any, may be collectible from our customers. Any amount we are unable to
resolve or collect from our customers will negatively impact the future results
of our natural gas pipelines and plants segment.

YEAR ENDED 2003 COMPARED TO YEAR ENDED 2002

Natural gas pipelines and plants margin for the year ended December 31,
2003 was $199.4 million higher than in 2002, primarily attributed to these asset
acquisition:

Margin also increased by $4.4 million due to an increase in volumes on our
Falcon Nest Pipeline, which was placed in service in March 2003, and $3.8
million due to additional volumes on our Viosca Knoll system from the Canyon
Express pipeline system and from the Medusa and Matterhorn natural gas
pipelines, which were placed in service during the latter part of the fourth
quarter of 2003. Additionally, margin increased due to higher NGL prices in
2003, which increased our processing margins at the Chaco facility by $2.0
million and at the Indian Basin gas plant by $4.5 million. Partially offsetting
these increases was a $3.0 million decrease in margin for our Texas intrastate
pipeline system attributable to the impact that higher natural gas prices in
2003 had on our fuel costs and the revaluation of our natural gas imbalances.
The increases were also offset by an additional $3.3 million decrease in margin
related to lower volumes on our HIOS pipeline due to natural decline in the
western region of the Gulf of Mexico.

Operating expenses excluding depreciation, depletion, and amortization for
the year ended December 31 2003, was $58.1 million higher than the same period
in 2002 primarily due to the acquisition of the San Juan and EPN Holding assets.
Excluding the operating costs of these acquired assets, operating expenses
increased by $9.8 million primarily due to higher repair and maintenance
expenses of $7.3 million, of which $6.0 million relates to expenditures on our
Texas intrastate pipeline, which were unusually low in 2002 due to timing of
expenditures, and $1.3 million attributable to repairs on our Viosca Knoll gas
pipeline extension, which was damaged by a ship anchor after construction.
Further contributing to the increase was higher expenses associated with an
increase in our allowance for doubtful accounts of $1.5 million in 2003.

Other income and cash distributions from unconsolidated affiliates in
excess of earnings for the year ended December 31, 2003, primarily relates to
earnings from our unconsolidated affiliate, Coyote Gas Treating, L.L.C., which
we acquired in connection with the San Juan asset acquisition in November 2002.

The noncash hedge gain for the year ended December 31, 2002, is related to
our San Juan hedging activity prior to our acquisition of the San Juan assets in
November 2002. Prior to this acquisition we accounted for this activity under
mark-to-market accounting since it did not qualify for hedge accounting under
SFAS No. 133.

44

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 $1.1 million in 2002 primarily as a result of a $0.6 million
decrease due to Hurricane Isidore in September 2002 and Hurricane Lili in
October 2002.

Operating expenses excluding depreciation, depletion and amortization for
the year ended December 31, 2002 were $72.1 million higher than the same period
in 2001 including $28.2 million related to our April 2002 purchase of the EPN
Holding assets, $4.5 million related to our purchase of the Chaco plant, $12.1
million related to our consolidation of Deepwater Holdings and $1.9 million
related to 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 GulfTerra Alabama Intrastate's
operating fee of $1.2 million and an increase in gas imbalance costs on our
Viosca Knoll system of $1.0 million.

Other income (expenses) and cash distributions from unconsolidated
affiliates in excess of earnings for the year ended December 31, 2002, was $11.9
million lower than the same period in 2001 primarily due to our consolidation of
Deepwater Holdings in October 2001.

OIL AND NGL LOGISTICS

The Oil and NGL logistics segment includes the Poseidon, Allegheny and
Typhoon offshore oil pipelines, the Texas NGL transportation pipelines and
fractionation plants, the Almeda fractionator and other Texas NGL assets. 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. The Texas plants fractionate NGLs 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 Texas facilities from a subsidiary of El
Paso Corporation. We have dedicated 100 percent of our Texas fractionation
facilities' capacity to this subsidiary of El Paso Corporation.

45

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

- ----------

(1) Earnings from unconsolidated affiliates for the years ended December 31,
2003, 2002, and 2001, was $8,098, $13,445 and $18,210.

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

(3) Represents 100 percent of Poseidon volumes.

(4) Represents a gain of $19 million associated with the sale of our 50 percent
interest in Cameron Highway to Valero Energy Corporation in July 2003. Refer
to previous discussion regarding Cameron Highway Oil Pipeline Company under
Capital Expenditures in this Item 7.

The majority of the earnings from the Oil and NGL logistics segment are
generated from volume-based fees for providing transportation of oil and NGLs
and fractionation of NGLs. However, many of the agreements with the customers on
our oil pipelines require that we purchase oil from the customer at the inlet of
our pipeline for an index price, less an amount that compensates us for
transportation services, and resell the oil to the customer at the outlet of our
pipeline at the same index price. We record these transactions based on the net
amount billed to our customers resulting in these transactions reflecting a fee
for transportation services.

Margin is driven by product pricing for both oil and NGLs and volumes. Both
oil and NGLs volumes are impacted by natural resource decline as well as
increases in new production. Volumes at our NGL fractionation plants are
significantly impacted by processing economics, which are driven by the
difference between natural gas prices and NGL prices. In 2003, natural gas
prices have been high relative to NGL prices resulting in poor processing
economics that reduce the amount of NGLs extracted from natural gas and
available for fractionation. We expect these economics to continue into next
year.

YEAR ENDED 2003 COMPARED TO YEAR ENDED 2002

For the year ended December 31, 2003, margin was $15.7 million higher than
the same period in 2002. Our acquisition in November 2002 of the NGL pipeline
systems and Typhoon Oil Pipeline contributed approximately $17.3 million and
$2.3 million to the increase. Partially offsetting this increase was a $4.1
million decrease in margin at our NGL plants due to lower volumes resulting from
poor processing economics.

Operating expenses excluding depreciation, depletion and amortization for
the year ended December 31, 2003 were $11.8 million higher than the same period
in 2002, primarily due to increased operating expenses of $9.7 million related
to our November 2002 acquisition of the Typhoon Oil pipeline and
46

the NGL pipeline systems. Excluding assets purchased, our operating expenses
excluding depreciation, depletion and amortization were $2.1 million higher
primarily due to increased operating expenses related to well testing on the
Anse La Butte NGL Storage facility and the Hattiesburg NGL Storage facility.

Other income and cash distributions from unconsolidated affiliates in
excess of earnings for the year ended December 31, 2003, were $5.3 million and
$1.8 million lower than the same period in 2002. Poseidon experienced lower
earnings due to natural production declines on some of the older deepwater
fields, as well as production downtime at several new fields. In addition, in
October 2003, Poseidon began withholding distributions to fund its capital
expenditures related to its Front Runner project. As a result we received lower
cash distributions than in the same period in 2002.

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. Our acquisitions of the NGL fractionation plants in
February 2001, the Hattiesburg propane storage facility in January 2002, and the
Anse La Butte NGL storage facility in December 2001 contributed approximately
$0.6 million, $1.2 million and $1.6 million to the increase. Additionally, in
November 2002, we purchased the NGL pipeline systems and the Typhoon Oil
pipeline, and these assets contributed $0.1 million and $0.5 million to the
increase. Excluding assets purchased, our margin was $1.2 million higher
primarily as a result of higher volumes on Allegheny.

Operating expenses excluding depreciation, depletion, and amortization for
the year ended December 31, 2002, were $3.1 million higher than the same period
in 2001 primarily due to increased operating expenses of $2.1 million related to
our acquisitions of the NGL fractionation plants 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 NGL pipeline
systems in November 2002. Excluding assets purchased, our operating expenses
excluding depreciation, depletion and amortization were $1.0 million lower as a
result of modifying the operating agreement in connection with the EPN Holding
acquisition in April 2002 between our NGL fractionation plants and El Paso Field
Services.

Other income and cash distributions from unconsolidated subsidiaries in
excess of earnings for the year ended December 31, 2002, declined $4.8 million
and $1.6 million from the 2001 period. These declines are due to decreases in
earnings from unconsolidated affiliates of $4.8 million as a result of lower
volumes on the Poseidon Oil Pipeline partially attributable to Hurricane Isidore
in September 2002 and Hurricane Lili in October 2002. Offsetting volume
decreases were additional volumes generated from new contracts entered into by
Poseidon Oil Pipeline. These contracts began in November 2002 and December 2002
and had a six month duration. We realized our 36 percent share of the volume
increase through earnings from unconsolidated affiliates.

NATURAL GAS STORAGE

The Natural gas storage segment includes the Petal and Hattiesburg storage
facilities and related pipeline, 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.

For the periods included in the following table, 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 actually used. We

47

also receive fees for injections and withdrawals by our customers and
interruptible storage fees. The following table presents performance cash flows
derived from our Natural gas storage segment:

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

(1) The amount in 2003 represents our gain on the sale of Copper Eagle to El
Paso Natural Gas Company in excess of cash distributions we received.

(2) Combined injections and withdrawals volumes.

At our Petal and Hattiesburg Storage facilities, we collect fixed and
variable fees for providing storage services, some of which is generated from
customers with cashout provisions, calculated by reference to a tariff-based
index. We incur expenses, which are reflected as cost of natural gas, as we
maintain these volumetric imbalance receivables and payables, all of which are
valued at current gas prices. For these reasons, we believe that gross margin
(revenues less cost of natural gas and other products) provides a more accurate
and meaningful basis for analyzing operating results for the natural gas storage
segment. Cost of natural gas reflects the initial loss of base gas in our
storage facilities or the encroachment on our base gas by third parties at the
market price in the period of the loss or encroachment and the monthly
revaluation of these amounts based on the monthly change in natural gas prices.

YEAR ENDED 2003 COMPARED TO YEAR ENDED 2002

For the year ended December 31, 2003, margin was $13.5 million higher than
the same period in 2002. An increase in subscribed firm storage capacity
attributable to the expansion of the Petal storage facility, which was completed
in June 2002, and our acquisition of the Wilson storage facility lease in April
2002, accounted for approximately $12.1 million and $1.6 million of the
increase.

YEAR ENDED 2002 COMPARED TO YEAR ENDED 2001

Natural gas storage margin for the year ended December 31, 2002, was $9.2
million higher than the same period in 2001. The expansion of our Petal storage
facility and our acquisition of the Wilson storage facility lease in April 2002
accounted for approximately $7.2 million and $4.3 million of the increase.
Excluding the

48

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 interruptible storage services.

Operating expenses excluding depreciation, depletion and amortization for
the year ended December 31, 2002, were $5.8 million higher than the same period
in 2001 including $0.6 million related to the expansion of our Petal storage
facility in the second quarter of 2002, $4.7 million related to the acquisition
of the Wilson storage facility lease in April 2002 and $0.6 million related to a
favorable resolution of an imbalance settlement in 2001.

PLATFORM SERVICES

The Platform services segment consists of the Falcon Nest, East Cameron
373, Viosca Knoll 817, Garden Banks 72, Ship Shoal 331, and Ship Shoal 332
platforms. These offshore platforms are primarily 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. 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 performance cash
flows derived from our Platform services segment and volumes associated with
each platform.

Our platform services segment generally earns revenue through demand fees
(regular payments made by customers using our platform services regardless of
volumes) and commodity charges (volume-based payments made by customers).
Contracts for platform services often include both demand fees and commodity
charges, but demand fees generally expire after a fixed period of time.

YEAR ENDED 2003 COMPARED TO YEAR ENDED 2002

For the year ended December 31, 2003, revenues from external customers were
$4.2 million higher than in the same period in 2002 of which $9.9 million is
attributable to the Falcon Nest fixed leg platform that went into operation in
March 2003. Partially offsetting this increase were lower revenues of $5.3
million from East Cameron 373 resulting from one time billing adjustments in
2002 for fixed monthly platform access fees, a gas dehydration fee, decreased
demand fees and lower production. Intersegment revenues were $6.7 million lower
due to the expiration in June 2002 and December 2002 of the fixed fee portion of
the Viosca Knoll 817 and Garden Banks 72 platform access fee contracts with one
of our wholly owned subsidiaries.

49

YEAR ENDED 2002 COMPARED TO YEAR ENDED 2001

Platform services revenue from external customers for the year ended
December 31, 2002, was $1.3 million higher than in the same period in 2001
primarily due to one-time billing adjustments for fixed monthly platform access
fees and a gas dehydration fee contract on the East Cameron 373 platform.

Platform services intersegment revenue for the year ended December 31, 2002
was $3.3 million lower than the same period in 2001 primarily due to the
expiration in June 2002 of the fixed fee portion of the Viosca Knoll 817
platform access fee contract with one of our wholly owned subsidiaries.

OTHER, NON-SEGMENT RESULTS

Our oil and natural gas production interests in the Garden Banks 72, Garden
Banks 117, Viosca Knoll 817 and West Delta 35 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 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. Accordingly, our focus
is to maximize the production from our existing portfolio of oil and natural gas
properties.

Also included in other, non-segment results are the quarterly payments we
receive from El Paso Corporation in connection with the sale of our Gulf of
Mexico assets in January 2001. El Paso Corporation agreed to pay us $2.25
million per quarter through the fourth quarter of 2003 and $2 million in the
first quarter of 2004, after which these payments will cease.

YEAR ENDED 2003 COMPARED TO YEAR ENDED 2002

Performance cash flows related to non-segment activity for the year ended
December 31, 2003, was $5.2 million higher than the same period in 2002 due to
lower demand fee expense of $6.7 million resulting from the expiration of the
fixed fee portion of the Viosca Knoll 817 contract in June 2002 and the Garden
Banks 72 contract in December 2002. Performance cash flows related to
non-segment activity also increased by $5.7 million due to higher oil and
natural gas prices in 2003. Partially offsetting these increases were lower
production from the Garden Banks 117 and Viosca Knoll 817 fields of $2.4 million
and higher operating expenses of $4.2 million associated with an increase in
professional fees, including legal, accounting and consulting services.

YEAR ENDED 2002 COMPARED TO YEAR ENDED 2001

Performance cash flows related to non-segment activity for the year ended
December 31, 2002, was $7.2 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 which resulted in decreased
revenues of $2.2 million. Further contributing to the decrease was lower
interest income of $1.3 million on the additional consideration from El Paso
Corporation related to the sale of the Gulf of Mexico assets as well as lower
revenue of $0.4 million due to Hurricane Isidore in September 2002 and Hurricane
Lili in October 2002.

50

DEPRECIATION, DEPLETION, AND AMORTIZATION

YEAR ENDED 2003 COMPARED TO YEAR ENDED 2002

Depreciation, depletion and amortization for the year ended December 31,
2003 was $26.7 million higher than the same period in 2002 primarily due to the
following:

Purchase of the San Juan assets in November 2002............ $ 20.4
Purchase of the EPN Holding assets in April 2002............ 5.3
Completion of the Petal expansion in July 2002.............. 3.0
Falcon Nest pipeline and platform, which went into operation
in March 2003............................................. 1.3
Decrease in depletion resulting from lower oil and natural
gas production............................................ (4.2)
Other....................................................... 0.9
------
$ 26.7
======

YEAR ENDED 2002 COMPARED TO YEAR ENDED 2001

Depreciation, depletion and amortization for the year ended December 31,
2002 was $37.3 million higher than the same period in 2001 primarily due to the
following:

Purchase of the EPN Holding assets in April 2002............ $15.5
Consolidation of Deepwater Holdings in October 2001......... 8.5
Purchase of the Chaco plant in October 2001................. 6.5
Completion of the Petal expansion in July 2002.............. 2.9
Purchase of the San Juan assets in November 2002............ 2.3
GTM Texas fractionation facilities acquired in February
2001...................................................... 0.8
Other....................................................... 0.8
-----
$37.3
=====

INTEREST AND DEBT EXPENSE

YEAR ENDED 2003 COMPARED TO YEAR ENDED 2002

Interest and debt expense, net of capitalized interest, for the year ended
December 31, 2003, was approximately $46.7 million higher than the same period
in 2002. This increase is primarily due to a higher outstanding balance on our
revolving credit facility and long-term debt and interest incurred on the
following indebtedness:

- our $230 million 8 1/2% senior subordinated notes that we issued in May
2002 and used to repay a portion of the GulfTerra Holding term credit
facility;

- our $160 million senior secured term loan that we entered into in October
2002 and refinanced in December 2003 to, among other things, expand the
existing term component from $160 million to $300 million;

- our $200 million 10 5/8% senior subordinated notes that we issued and our
$237.5 million senior secured acquisition term loan we entered into in
November 2002 in connection with our acquisition of the San Juan assets;
and

- our $300 million 8 1/2% senior subordinated notes that we issued in March
2003 and used to repay our $237.5 million senior secured acquisition term
loan.

In December 2003, we redeemed approximately $269.4 million in principal
amount of our senior subordinated notes, see Part II, Item 8, Financial
Statements and Supplementary Data, Note 6.

51

Capitalized interest for the year ended December 31, 2003 was $12.5
million, representing an increase of $6.9 million for the year ended December
31, 2002. The increase is the result of an increase in construction
work-in-process as a result of increased expenditures related to our
construction projects.

YEAR ENDED 2002 COMPARED TO YEAR ENDED 2001

Interest and debt expense related to continuing operations, net of
capitalized interest, for the year ended December 31, 2002, was approximately
$39.5 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.

LOSSES DUE TO EARLY REDEMPTIONS OF DEBT AND WRITE-OFF OF DEBT ISSUANCE COSTS

In March 2003, we repaid our $237.5 million senior secured acquisition term
loan which was due in May 2004 and recognized a loss of $3.8 million related to
the write-off of the unamortized debt issuance costs related to this loan.

In July 2003, we repaid our $160 million GTM Holding term credit facility
that was scheduled to mature in April 2005 and recognized a loss of $1.2 million
related to the write-off of the unamortized debt issuance costs associated with
this facility.

In December 2003, we refinanced the term loan portion of our credit
facility. We charged $2.8 million to expense in December 2003 to recognize the
unamortized debt issuance costs associated with the initial term loan.

In December 2003, we redeemed approximately $269.4 million in principal
amount of our senior subordinated notes and recognized a loss of $29.1 million
resulting from the payment of the redemption premiums and the write-off of
unamortized debt issuance costs, premiums and discounts.

In December 2002, we retired a portion of our GTM Holding term credit
facility and recognized a loss of $2.4 million related to the write-off of
unamortized debt issuance costs associated with this facility.

COMMITMENTS AND CONTINGENCIES

See Part II, Item 8, Financial Statements and Supplementary Data, Note 11,
for a discussion of our commitments and contingencies.

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 decisions 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 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
52

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. Our management has discussed the development and selection of the
critical accounting estimates related to the reported amounts of assets,
liabilities, revenues and expenses and disclosure of contingent assets and
liabilities with the audit and conflicts committee of our general partner's
board of directors and that committee has reviewed the related disclosures
discussed below.

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 Part II, Item 8, Financial Statements and
Supplementary Data, Note 1.

Reserves for Environmental and Legal Contingencies

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. We accrue
reserves for environmental matters when our assessments indicate that it is
probable that a liability has been incurred and an amount can be reasonably
estimated. Our assessments are based on studies, as well as site surveys, to
determine the extent of any environmental damage and determine the necessary
requirements to remediate this damage. 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.

These assessments incorporate an analysis by our internal environmental
engineering staff and consultation with legal counsel. An estimated range of the
costs involved is derived and a liability for environmental remediation is
recorded within this estimated range. The recorded liabilities for these issues
represent our best estimates of remediation and restoration that may be required
to comply with present laws and regulations. These estimates are based on
forecasts of the total future costs related to environmental remediation. These
estimates change periodically as additional or better information becomes
available as to the extent of site remediation required, if any. Certain changes
could occur that would materially affect our estimates and assumptions related
to costs for environmental remediation. If we become subject to more stringent
environmental remediation costs at known sites, if we discover additional
contamination, discover previously unknown sites, or become subject to related
personal or property damage, we could incur material costs in connection with
the environmental remediation. Accordingly, management believes that estimates
related to the accrual of environmental remediation liabilities are critical to
our results of operations.

As of December 31, 2003, our Natural Gas Pipelines and Plants segment had a
liability for environmental remediation of $21 million which was derived from a
range of reasonable estimates based upon our studies and site surveys described
above. In accordance with Statement of Financial Accounting Standards No. 5
"Accounting for Contingencies" and FASB Interpretation No. 14, "Reasonable
Estimation of the Amount of a Loss," we used the low end of the range which is
our best estimate of the loss. For environmental remediation sites known as of
December 31, 2003, if the highest estimate from the range (based upon
information presently available) were recorded, the total estimated liability
would have been $43 million at December 31, 2003.

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

53

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, Depletion and Amortization 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 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, depletion
and amortization 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.

If the average estimated useful lives of our depreciable assets were to
change, the most significant impact would be on depreciation, depletion and
amortization expense. A majority of this impact would be related to our pipeline
assets. If the average estimated remaining useful lives were to decrease by 10
percent, the annual depreciation, depletion and amortization expense for our
total assets would increase by $11.0 million, of which $7.3 million would be
related to our pipelines. If the average estimated remaining useful lives were
to increase by 10 percent, the annual depreciation, depletion and amortization
expense for our total assets would decrease by $9.0 million, of which $5.9
million would be related to our pipelines. The remaining variances in
depreciation, depletion and amortization expense are spread across our other
asset groups -- platforms and facilities, processing facilities and storage
facilities.

Revenue and Cost of Natural Gas and Other Products Estimates

Each month we record an estimate for our operating revenues and cost of
natural gas, oil and other products, including lost and unaccounted for, along
with a true-up of the prior month's estimate to equal prior month's actual data.
Accordingly, there is one month of estimated data recorded in our operating
revenues and cost of natural gas and other products accounts for the years ended
December 31, 2003, 2002 and 2001. 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. Based on average monthly revenues and cost
of natural gas and other products, a variance of 10 percent could impact
revenues up to a positive or negative $7.3 million, of which $6.1 million is
related to the Natural Gas Pipelines and Plants segment, and cost of natural gas
and other products up to a positive or negative $2.4 million, of which $2.0
million is related to the Natural Gas Pipelines and Plants segment.

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 as an asset or
liability 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.
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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 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. A 10 percent increase or decrease in the forward price curves at
December 31, 2003, would change our hedge liability by $8.8 million with an
eventual loss reported in the results operations when the hedged items settled.
These changes would impact our Natural Gas Pipelines and Plants segment.

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.

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 purchase, and the sale of production based on
volumetric calculations. Variances resulting from such calculations are inherent
in our business.

Natural 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-end spot prices
because it is not likely that we would purchase or receive natural gas at that
point in time to settle the imbalance.

Depending on our net position, a change in natural gas prices of 10 percent
could positively or negatively affect our results of operations by $2.9 million,
primarily in our Natural Gas Pipelines and Plants segment.

OFF-BALANCE SHEET ARRANGEMENTS

We have no off-balance sheet arrangements, as described in Item
303(a)(4)(ii) of Regulation S-K, that have or are reasonably likely to have a
material current or future effect on our financial condition, revenues,
expenses, results of operations, liquidity, capital expenditures or capital
resources.

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 effective, which will impact our
accounting when these rules are adopted in the future. Some of these new rules
may have an impact on our critical accounting policies.

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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.

Other than the subsection below entitled "Risks Related to Our Proposed
Merger with Enterprise", the following is a discussion of the risks associated
with our business, structure and other matters generally as it existed on
December 31, 2003 and does not take into account or assume the consummation of
our proposed merger with Enterprise.

RISKS RELATED TO OUR PROPOSED MERGER WITH ENTERPRISE

BECAUSE THE CONSIDERATION THAT OUR UNITHOLDERS WILL RECEIVE IN THE PROPOSED
MERGER WITH ENTERPRISE IS BASED ON A FIXED EXCHANGE RATIO, THE MARKET VALUE OF
OUR COMMON UNITS MAY BE SIGNIFICANTLY AFFECTED BY CHANGES IN THE MARKET VALUE
OF ENTERPRISE COMMON UNITS.

At the effective time of the merger, each holder of GulfTerra common units
will receive 1.81 Enterprise common units for each GulfTerra common unit held.
Because this exchange ratio is fixed, the market value of the consideration that
GulfTerra unitholders will receive depends on the trading price of Enterprise
common units. Accordingly, any changes in the market value of Enterprise common
units prior to the effective time of the merger would likely affect the market
value of GulfTerra common units, regardless of whether there had been any change
in the market's perception of GulfTerra's business, assets, liabilities or
prospects.

WE HAVE EXPENDED AND WILL EXPEND SIGNIFICANT TIME AND RESOURCES ON THE MERGER.

In addition to the economic costs associated with pursuing a merger, our
management is devoting substantial time and other human resources to the
proposed transaction and related matters. Towards this end, our management and
personnel are making the necessary filings, seeking the necessary approvals
(including unitholder approval) and preparing for the merger closing. These
activities, when coupled with the limitations imposed on us under the merger
agreement, are likely to limit our ability to pursue other attractive
non-organic business opportunities, including potential joint ventures,
acquisitions and other transactions. In addition, to be consummated, the merger
must be approved by Enterprise's unitholders and by our unitholders; we must
receive approval from the Federal Trade Commission; and all of the other
conditions to closing must have either been satisfied or waived. If the merger
is not consummated, for any reason, we probably will not receive a significant
return on our merger-related efforts.

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, 2003, we had approximately
$682 million outstanding of senior secured indebtedness,
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approximately $168.1 million outstanding of accounts payable and accrued gas
purchase costs and $1.13 billion outstanding under indentures related to our
senior unsecured and senior subordinated notes.

From time to time, our joint ventures also incur indebtedness. As of
December 31, 2003, Poseidon Oil Pipeline Company, L.L.C., in which we own a 36
percent interest, had $123 million outstanding under its revolving credit
facility, Deepwater Gateway, L.L.C., in which we own a 50 percent interest, had
$155 million outstanding under its project finance loan and Cameron Highway Oil
Pipeline Company, in which we own a 50 percent joint venture ownership interest,
had $125 million outstanding under its project loan facility. 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.

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 notes and 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. The
restrictions under our 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 the indentures relating to our senior
subordinated notes and our senior notes. 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 at least 50 percent of our
general partner,
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that would (1) be an event of default, unless our creditors agreed otherwise,
under our credit facility and (2) require us to offer to repurchase all of our
senior subordinated notes, and possibly all of our senior 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
ILLIQUID 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 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.

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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 need to reduce or reprioritize our capital budget,
sell non-core assets, access the capital markets or reduce or eliminate
distributions to unitholders to meet our capital requirements.

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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 2003 AND 2002 AND WHICH EXPIRE BETWEEN 2006 AND
2008.

For the year ended December 31, 2003 and 2002, approximately 70 percent of
the volume attributable to the San Juan gathering system is derived from
contracts with three major customers, Burlington Resources, ConocoPhillips and
BP. These contracts expire in December of 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 years ended December 31, 2003 and
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 consolidated statement
of income only includes San Juan from the acquisition date.

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 notes and our senior subordinated notes, are fixed and the
interest rates on some of our other indebtedness, like our 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.

CHANGES IN THE PRICES OF HYDROCARBON PRODUCTS MAY ADVERSELY AFFECT OUR RESULTS
OF OPERATIONS, CASH FLOWS AND FINANCIAL CONDITION.

We gather, transport, process, fractionate and store natural gas, NGLs and
crude oil. As such, our results of operations, cash flows and financial position
may be adversely affected by changes in the prices of these hydrocarbon products
and by changes in the relative price levels among these hydrocarbon products. In
general terms, the prices of natural gas, NGLs, crude oil and other hydrocarbon
products are subject to fluctuations in response to changes in supply, market
uncertainty and a variety of additional factors that are impossible to control.
These factors include:

- the level of domestic production;

- the availability of imported oil and natural gas;

- actions taken by foreign oil and natural gas producing nations;

- the availability of transportation systems with adequate capacity;

- the availability of competitive fuels;

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- fluctuating and seasonal demand for oil, natural gas and NGLs; and

- conservation and the extent of governmental regulation of production and
the overall economic environment.

The profitability of our natural gas processing operations will depend upon
the spread between NGL product prices and natural gas prices. A reduction in the
spread between NGL product prices and natural gas prices can result in a
reduction in demand for fractionation, processing and NGL storage services and,
thus, may adversely affect our results of operations and cash flows from these
activities. In addition, our natural gas processing activities will be exposed
to commodity price risk associated with the relative price of NGLs to natural
gas under our "keep-whole" natural gas processing contracts. Under these types
of agreements, we take title to NGLs that we extract from the natural gas stream
and are obligated to pay market value, based on natural gas prices, for the
energy extracted from the natural gas stream. When prices for natural gas
increase, the cost to us of making these "keep-whole" payments will increase,
and, where NGL prices do not experience a commensurate increase, we will realize
lower margins from these transactions. As a result, changes in prices for
natural gas compared to NGLs could have an adverse affect on our results of
operations, cash flows and financial position.

We are also exposed to natural gas and NGL commodity price risk under
natural gas processing and gathering and NGL fractionation contracts that
provide for our fee to be calculated based on a regional natural gas or NGL
price index or to be paid in-kind by taking title to natural gas or NGLs. Over
95% of the volumes handled by our San Juan gathering system are fee-based
arrangements, 80% of which are calculated as a percentage of a regional natural
gas price index. A decrease in natural gas and NGL prices can result in lower
margins from these activities, which may adversely affect our results of
operations, cash flows and financial position.

A DECLINE IN THE VOLUME OF NATURAL GAS, NGLS AND CRUDE OIL DELIVERED TO OUR
FACILITIES COULD ADVERSELY AFFECT OUR RESULTS OF OPERATIONS, CASH FLOWS AND
FINANCIAL POSITION.

Our profitability could be materially impacted by a decline in the volume
of natural gas, NGLs and crude oil transported, gathered or processed at our
facilities. A material decrease in natural gas or crude oil production or crude
oil refining, as a result of depressed commodity prices, a decrease in the
exploration and development activities or otherwise, could result in a decline
in the volume of natural gas, NGLs and crude oil handled by our facilities.

The crude oil, natural gas and NGLs available to our facilities will be
derived from reserves produced from existing wells, which reserves naturally
decline over time. To offset this natural decline, our facilities will need
access to additional reserves. Additionally, some of our facilities will be
dependent on reserves that are expected to be produced from newly discovered
properties that are currently being developed.

Exploration and development of new oil and natural gas reserves is capital
intensive, particularly offshore in the Gulf of Mexico. 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 are out of our control and can
adversely affect the decision by producers 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. For example, a sustained decline in the price of
natural gas and crude oil could result in a decrease in natural gas and crude
oil exploration and development activities in the regions where our facilities
are located. This could result in a decrease in volumes to our offshore
platforms, natural gas processing plants, natural gas, crude oil and NGL
pipelines, and NGL fractionators which would have an adverse affect on our
results from operations, cash flows and financial position. Additional reserves,
if discovered, may not be developed in the near future or at all.

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A REDUCTION IN DEMAND FOR NGL PRODUCTS BY THE PETROCHEMICAL, REFINING OR
HEATING INDUSTRIES COULD ADVERSELY AFFECT OUR RESULTS OF OPERATIONS, CASH
FLOWS AND FINANCIAL POSITION.

A reduction in demand for NGL products by the petrochemical, refining or
heating industries, whether because of general economic conditions, reduced
demand by consumers for the end products made with NGL products, increased
competition from petroleum-based products due to pricing differences, adverse
weather conditions, government regulations affecting prices and production
levels of natural gas or the content of motor gasoline or other reasons, could
adversely affect our results of operations, cash flows and financial position.

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

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

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, 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 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

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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;

- 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 November 2003, the FERC issued a Final Rule extending its 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 facility, including the 60-mile Petal gas pipeline,
are interstate facilities as defined by the Natural Gas Act, the regulations
dictate how HIOS and Petal conduct business and interact with all energy
affiliates of El Paso Corporation and us.

The standards of conduct require us, absent a waiver, to functionally
separate our HIOS and Petal interstate facilities from our other entities. We
must dedicate employees to manage and operate our interstate facilities
independently from our other Energy Affiliates. This employee group must
function independently and is prohibited from communicating non-public
transportation information or customer information to its Energy Affiliates.
Separate office facilities and systems are necessary because of the requirement
to restrict affiliate access to interstate transportation information. The Final
Rule also limits the sharing of employees and offices with Energy Affiliates.
The Final Rule was effective on February 9, 2004, subject to possible rehearing.
On that date, each transmission provider filed with the FERC and posted on the
internet website a plan and schedule for implementing this Final Rule. By June
1, 2004, written procedures implementing this Final Rule will be posted on the
internet website. Requests for rehearing have been filed and are pending. At
this time, we cannot predict the outcome of these requests, but at a minimum,
adoption of the regulations in the form outlined in the Final Rule will place
additional administrative and operational burdens on us.

Given the extent of this regulation, the extensive changes in the 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.

OUR PIPELINE INTEGRITY PROGRAM MAY IMPOSE SIGNIFICANT COSTS AND LIABILITIES TO
US.

In December 2003, the U.S. Department of Transportation issued a Final Rule
requiring pipeline operators to develop integrity management programs for gas
transmission pipelines located where a leak or rupture could do the most harm in
"high consequence areas", or HCA. The final rule requires operators to (1)
perform ongoing assessments of pipeline integrity; (2) identify and characterize
applicable threats to pipeline segments that could impact an HCA; (3) improve
data collection, integration and analysis; (4) repair

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and remediate the pipeline as necessary; and (5) implement preventive and
mitigative actions. The final rule incorporates the requirements of the Pipeline
Safety Improvement Act of 2002, a new bill signed into law in December 2002. The
Final Rule is effective as of January 14, 2004. At this time, we cannot predict
the impact this Final Rule will have on our results of operations.

Our pipeline integrity testing program, which is intended to assess and
repair the integrity of our pipelines, is underway. While the costs associated
with the pipeline integrity testing itself are not large, the results of these
tests could cause us to incur significant and unanticipated capital and
operating expenditures to ensure the safe and reliable operation of our
pipelines.

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 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. We expect to maintain adequate insurance coverages, although it will
not cover many types of interruptions that might occur. As a result of market
conditions, premiums and deductibles for certain insurance policies can increase
substantially, and in some instances, certain insurance may become unavailable
or available only for reduced amounts of coverage. As a result, we may not be
able to renew our existing insurance policies or procure other desirable
insurance on commercially reasonable terms, if at all. If we were to incur a
significant liability for which we were not fully insured, it could have a
material adverse effect on our financial position. In addition, the proceeds of
any such insurance may not be paid in a timely manner and may be insufficient if
such an event were to occur.

TERRORIST ATTACKS AIMED AT OUR FACILITIES COULD ADVERSELY AFFECT OUR BUSINESS.

Since the September 11, 2001 terrorist attacks on the United States, the
United States government has issued warnings that energy assets, including our
nation's pipeline infrastructure, may be the future target of terrorist
organizations. Any terrorist attack on our facilities, those of our customers
and, in some cases, those of other pipelines, could have a material adverse
effect on our business. An escalation of political tensions in the Middle East
and elsewhere could result in increased volatility in the world's energy markets
and result in a material adverse effect on our business.

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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 $764 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 $750 million, net $752 million after
adjustments for capital expenditures and actual working capital acquired;

- in October 2003, we released El Paso Corporation from its obligation, in
connection with our November 2002 San Juan asset acquisition, to
repurchase the Chaco plant from us in 2021 in exchange for El Paso
Corporation contributing specified communication assets to us;

- in October 2003, we redeemed our Series B preference units, which were
owned by a subsidiary of El Paso Corporation, for approximately $156
million; 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 affiliates do not, and will not be
required to, spend any specified percentage or amount of time on our business.
Since these shared officers and directors 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 directors,
officers and other personnel own and are 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 common unit holders.

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 affiliates 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.

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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 (or any of its other competitors acquired by El Paso
Corporation). In fact, El Paso Corporation may have financial motives to favor
our competitors. 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.

EL PASO CORPORATION 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, El Paso Corporation and its
affiliates own 10,310,045 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

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- 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. Neither El Paso Corporation
nor any of its other subsidiaries, other than our general partner, owes
fiduciary duties to us.

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

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 debt service;

- providing for future operating and capital expenditures;

- 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
affiliates 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 affiliates, 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.

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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 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

WE MAY NOT HAVE SUFFICIENT CASH FROM OPERATIONS TO PAY DISTRIBUTIONS AT THE
CURRENT LEVEL FOLLOWING ESTABLISHMENT OF CASH RESERVES AND PAYMENTS OF FEES
AND EXPENSES, INCLUDING PAYMENTS TO OUR GENERAL PARTNER.

Because distributions on our common units are dependent on the amount of
cash we generate, distributions may fluctuate based on our performance. We
cannot guarantee that we will continue to pay distributions at the current level
each quarter. The actual amount of cash that is available to be distributed each
quarter will depend upon numerous factors, some of which are beyond our control
and the control of our general partner. These factors include but are not
limited to the following:

- the level of our operating costs;

- the level of competition in our business segments;

- prevailing economic conditions;

- the level of capital expenditures we make;

- the restrictions contained in our debt agreements and our debt service
requirements;

- fluctuation in our working capital needs;

- the cost of acquisitions, if any; and

- the amount, if any, of cash reserves established by our general partner,
in its direction.

In addition, you should be aware that our ability to pay the minimum
quarterly distribution each quarter depends primarily on our cash flow,
including cash flow from financial reserves, working capital borrowings and
distributions from our unconsolidated affiliates, and not solely on
profitability, which is affected by non-cash items. As a result, we may make
cash distributions during periods when we record losses and we may not make
distributions during periods when we record net income.

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 our 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.

Our general partner may not be removed as our general partner except upon
approval by the affirmative vote of the holders of at least 66 2/3 percent of
our outstanding limited partner interests (excluding 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

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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 2003,
we issued through public and private offerings 14,026,109 additional common
units and 80 Series F convertible units, which may ultimately convert into a
maximum of 8,329,679 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 CERTAIN CIRCUMSTANCES, 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 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

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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. They
may also incur a tax liability upon sale of their units.

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 and possibly our outstanding senior 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.

THE EXISTENCE OF THE SERIES F CONVERTIBLE UNITS COULD DEPRESS THE MARKET PRICE
OF OUR COMMON UNITS.

The terms on which we are able to obtain additional capital may be
adversely affected while our Series F convertible units (and other securities
convertible into or exercisable for common units) are outstanding

70

because of the uncertainty and potential dilutive effect related to conversion
or exercise of our Series F convertible units and other derivative securities.

THE SERIES F CONVERTIBLE UNITS WERE ACQUIRED BY A SINGLE INVESTOR WHICH
RESULTED IN CONCENTRATED OWNERSHIP AND COULD DEPRESS THE MARKET PRICE OF OUR
COMMON UNITS.

All of our Series F convertible units were acquired by one investor, and
assuming that investor retains a substantial portion of the Series F convertible
units and converts them to common units, that investor could own approximately
15 percent of our outstanding common units. In the future, that investor may
acquire additional common units or dispose of some or all of its common units.
If that investor were to dispose of a substantial portion of its common units in
the trading markets, it could reduce the market price of our common units.

PROPOSED STATE TAX LEGISLATION MAY AFFECT OUR CASH FLOW AND DISTRIBUTIONS.

Several states are evaluating ways to subject partnerships to entity-level
taxation through the imposition of state income, franchise or other forms of
taxation. If certain states were to impose a tax upon us as an entity, the cash
available for distribution to you would be reduced. Our partnership agreement
provides that, if a law is enacted or existing law is modified or interpreted in
a manner that subjects us to taxation as a corporation or otherwise subjects us
to entity-level taxation for federal, state or local income tax purposes, then
the minimum quarterly distribution and the target distribution levels will be
decreased to reflect that impact on us.

RISKS RELATED TO OUR LEGAL STRUCTURE

THE INTERRUPTION OF DISTRIBUTIONS TO US FROM OUR SUBSIDIARIES AND JOINT
VENTURES MAY AFFECT OUR ABILITY TO MAKE 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)
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. For example, we expect to receive no distributions
from Poseidon until it has completed its Front Runner pipeline project.

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, Cameron
Highway Oil Pipeline Company 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,
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transactions with affiliates of a joint venture participant, litigation and
transactions not in the ordinary course of business, among others. For example,
we expect to receive no distributions from Poseidon until it has completed its
Front Runner pipeline project. 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, 2003, our aggregate investments in Deepwater Gateway, Cameron Highway Oil
Pipeline Company, Coyote Gas Treating, L.L.C. and Poseidon totaled $33 million,
$86 million, $16.7 million and $40 million.

In addition, each joint venture's charter documents typically vest in its
management committee sole discretion regarding the occurrence and amount of
distributions. Some of the joint ventures in which we participate have separate
credit arrangements that contain various restrictive covenants. Among other
things, those covenants may limit or restrict the joint venture's ability to
make distributions to us under certain circumstances. Accordingly, our joint
ventures may be unable to make distributions to us at current levels or at all.

Moreover, we cannot be certain that any of the joint venture owners will
not sell, transfer or otherwise modify their ownership interest in a joint
venture, whether in a transaction involving third parties and/or the other joint
venture owners. Any such transaction could result in us partnering with
different or additional parties.

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.

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 a 50 percent managing
member interest in our general partner, common units, and Series C 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. If El Paso Corporation owns less than 50 percent of our
general partner (including at the closing of our merger with Enterprise), that
would constitute a change of control under our existing credit agreement, our
senior subordinated notes indentures and possibly the indenture relating to the
senior notes. In such a circumstance, much of 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.

TAX RISKS

WE HAVE NOT RECEIVED A RULING OR ASSURANCES FROM THE IRS WITH RESPECT TO OUR
CLASSIFICATION AS A PARTNERSHIP.

We have not requested 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

72

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
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.

73

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. Distributions to foreign persons will be
reduced by withholding taxes at the highest effective U.S. federal income tax
rate for individuals. 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.

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. The tax laws require that some types of
entities, including some partnerships, register as "tax shelters" in response to
the perception that they claim tax benefits that may be unwarranted. 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 INVESTOR 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.

74

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.

75

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 2003 and 2002.

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 may 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 February and August 2003,
we entered into additional derivative financial instruments to continue to hedge
our exposure during 2004 to changes in natural gas prices relating to gathering
activities in the San Juan Basin. The derivatives are financial swaps on 30,000
MMBtu per day whereby we receive an average fixed price of $4.23 per MMBtu and
pay a floating price based on the San Juan index. We are accounting for these
derivatives as cash flow hedges under SFAS No. 133.

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
received a fixed price based on the daily average price for the
76

specified contract month based upon the OPIS posting prices for the particular
month for established volumes that settled over the same time periods we
expected 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.

During 2003, we entered into additional derivative financial instruments to
hedge a portion of our business' exposure to changes in NGL prices during 2003
and 2004. We entered into financial swaps for 3,500 barrels per day for February
through June 2003, 3,200 barrels per day for July 2003, 4,900 barrels per day
for August 2003, and 6,000 barrels per day for August 2003 through September
2004. The average fixed price received was $0.49 per gallon for 2003 and will be
$0.47 per gallon for 2004 while we pay a monthly average floating price based on
the OPIS average price for each month.

During 2002 and 2003, our GulfTerra Alabama Intrastate 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.

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.

- ----------

(b) Fair value is determined from prices indicated in the San Juan index as
developed from market data.

As reflected in the tables above, at December 31, 2003 we have an
unrealized loss associated with our natural gas and NGL fixed-for-floating
commodity price swaps of approximately $9.0 million.

77

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 revolving
credit facility and senior secured term loan and from our fixed for floating
interest rate swap agreement on $250 million of our 8 1/2% senior subordinated
notes due 2011. We are exposed to similar risk under the various joint venture
credit facilities and loan agreements. Since we have $1,137.2 million
outstanding under our indentures at fixed interest rates ranging from 6 1/4% to
10 5/8% at December 31, 2003, 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.

78

The table below depicts principal cash flows and related weighted average
interest rates of our debt obligations, by expected maturity dates at December
31, 2003. The carrying amounts of our revolving credit facility, GulfTerra
Holding term credit facility and the senior secured term loans at December 31,
2003 and 2002, approximate the fair value of these instruments because the
variable interest rates on these loans reprice frequently to reflect currently
available interest rates. The fair value of the senior notes and senior
subordinated notes has been determined based on quoted market prices for the
same or similar issues.

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

(1) The December 31, 2003 amounts exclude the market value ($7.4 million
liability at December 31, 2003) of our interest rate swap accounted as a
fair value hedge.

At December 31, 2003, we had variable rate debt outstanding with an
aggregate principal balance of $682.0 million and a weighted average interest
rate of 3.3%. 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, 2003
(dollars in millions):

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

Because the closing of the merger with Enterprise will constitute a change
of control, and thus a default, under our credit facility, we will either amend
or refinance our credit facility prior to that closing. In addition, because the
closing of the Enterprise merger will constitute a change of control under our
indentures, we will be required to offer to repurchase all of our senior
subordinated notes (and possibly our senior notes) at 101 percent of their par
value after the closing. In coordination with Enterprise, we are evaluating
alternative financing plans in preparation for the close of the merger. We and
Enterprise can agree on the date of the merger closing after the receipt of all
necessary approvals. We do not intend to close until appropriate financing is in
place.

In December 2003, we exercised our right, under the terms of our senior
subordinated notes' indentures, to repay, at a premium, approximately $269.4
million in principal amounts of those senior subordinated notes. The indentures
provide that, within 90 days of an equity offering, we can call up to 33% of the
original face amount at a premium. The amount we can repay is limited to the net
proceeds of the offering. We recognized

79

additional costs totaling $29.1 million resulting from the payment of the
redemption premiums and the write-off of unamortized debt issuance costs,
premiums and discounts.

In March 2004, we gave notice to exercise our right, under the terms of our
senior subordinated notes' indentures, to repay, at a premium, approximately
$39.1 million in principal amount of those senior subordinated notes. The
indentures provide that, within 90 days of an equity offering, we can call up to
33 percent of the original face amount at a premium. The amount we can repay is
limited to the net proceeds of the offering. We will recognize additional costs
totaling $4.1 million resulting from the payment of the redemption premiums and
the write-off of unamortized debt issuance costs. We will account for these
costs as an expense during the second quarter of 2004 in accordance with the
provisions of SFAS No. 145.

In July 2003, to achieve a better mix of fixed rate debt and variable rate
debt, we entered into an eight-year interest rate swap agreement to provide for
a floating interest rate on $250 million out of $480.0 million of our 8 1/2%
senior subordinated notes due 2011. With this swap agreement, we pay the
counterparty a LIBOR based interest rate plus a spread of 4.20% (which rate was
1.55% at December 31, 2003) and receive a fixed rate of 8 1/2%. We are
accounting for this derivative as a fair value hedge under SFAS No. 133. At
December 31, 2003, the fair value of the swap was a liability, included in
non-current liabilities, of approximately $7.4 million. The fair value of the
hedged debt decreased by the same amount.

At December 31, 2003, 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 $123 million outstanding. In January 2002, Poseidon
entered into a two-year interest rate swap agreement to fix the interest rate at
3.49% through January 2004 on $75 million of the amounts outstanding on their
variable rate revolving credit facility. This interest rate swap expired in
January 2004 and was not renewed.

80

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

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

See accompanying notes.
81

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

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

See accompanying notes.
82

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)

See accompanying notes.
83

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

84

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS -- (CONTINUED)
(IN THOUSANDS)

See accompanying notes.

85

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(IN THOUSANDS)

- ---------------
(1) In October 2003, we redeemed all of our remaining outstanding Series B
preference units for $156 million.
(2) 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.
(3) GulfTerra Energy Company, L.L.C. is our sole general partner and is owned 50
percent by a subsidiary of El Paso Corporation and 50 percent by a
subsidiary of Enterprise Products Partners, L.P.
(4) Income allocation to our general partner includes both its incentive
distributions and its one percent ownership interest.

See accompanying notes.
86

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

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

COMPREHENSIVE INCOME

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

See accompanying notes.
87

GULFTERRA 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, 2003, we had 58,404,649 common units outstanding
representing limited partner interests and 10,937,500 Series C units outstanding
representing non-voting limited partner interests. On that date, the public
owned 48,020,404 common units, or 82.2 percent of our outstanding common units,
and El Paso Corporation, through its subsidiaries, owned 10,384,245 common
units, or 17.8 percent of our outstanding common units, all of our Series C
units and 50 percent of our general partner, which owns our one percent general
partner interest.

In May 2003, we changed our name to GulfTerra Energy Partners, L.P. from El
Paso Energy Partners, L.P. and reorganized our general partner. In connection
with our name change, we also changed the names of several subsidiaries in May
2003, including the following, as listed in the table below.

Our sole general partner is GulfTerra Energy Company, L.L.C., a
recently-formed Delaware limited liability company that is owned 50 percent by a
subsidiary of El Paso Corporation and 50 percent by a subsidiary of Enterprise,
a publicly traded master limited partnership. El Paso Corporation (through its
subsidiaries) owned 100 percent of our general partner until October 2003, when
Goldman Sachs acquired a 9.9 percent interest in our general partner. In
December 2003, El Paso Corporation reacquired Goldman Sachs' interest in our
general partner and then sold a 50 percent interest in our general partner to a
subsidiary of Enterprise.

On December 15, 2003, we, along with Enterprise and El Paso Corporation,
announced that we had executed definitive agreements to merge Enterprise and
GulfTerra to form one of the largest publicly traded MLPs with Enterprise being
the continuing entity. The general partner of the combined partnership will be
jointly owned by affiliates of El Paso Corporation and privately-held Enterprise
Products Company, with each owning a 50-percent interest.

The combined partnership, which will retain the name Enterprise Products
Partners L.P., will serve the largest producing basins of natural gas, crude oil
and NGLs in the U.S., including the Gulf of Mexico, Rocky Mountains, San Juan
Basin, Permian Basin, South Texas, East Texas, Mid-Continent and Louisiana Gulf
Coast basins and, through connections with third-party pipelines, Canada's
western sedimentary basin. The partnership will also serve the largest consuming
regions for natural gas, crude oil and NGLs on the U.S. Gulf Coast.

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

88

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

in our consolidated financial statements. In May 2001, we purchased our general
partner's one percent non-managing ownership interest in twelve of our
subsidiaries for $8 million. As a result of this acquisition, all of our
subsidiaries, but not our equity investees, are wholly-owned by us.

During part of 2003 and 2002, third parties had minority ownership
interests in Matagorda Island Area Gathering System (MIAGS) and Arizona Gas,
L.L.C. The assets, liabilities and operations of these entities are included in
our consolidated financial statements and we account for the third party
ownership interest as minority interest in our consolidated balance sheets and
as minority interest income (expense) in our consolidated statements of income.
In October 2003, we purchased the remaining 17 percent interest in MIAGS. As a
result, we no longer recognize the third party ownership interest in MIAGS as
minority interests in our consolidated balance sheets or consolidated statements
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 the years ended December 31, 2002 and
2001. 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.

Under the provisions of SFAS No. 143, Accounting for Asset Retirement
Obligations, which we adopted on January 1, 2003, the cost associated with the
retirement of long-lived assets for regulated entities accounted for under SFAS
No. 71 should be classified as a regulatory liability instead of as a component
of property, plant and equipment. As a result, we reclassified $13.6 million
from property, plant and equipment to a regulatory liability and at December 31,
2003, this balance is included in other noncurrent liabilities in our
consolidated balance sheet. Prior to January 2003, this item was reflected in
accumulated depreciation, depletion and amortization and the balance for this
item at December 31, 2002, was $12.9 million.

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.

89

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 that we believe are
uncollectible. We review collectibility regularly and adjust the allowance as
necessary, primarily under the specific identification method. At December 31,
2003 and 2002, the allowance was $4.0 million and $2.5 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. We 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-end spot 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 imbalance receivables and imbalance payables were as follows
at December 31 (in thousands):

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. In addition, we reduce our
property, plant and equipment balance for any amounts that we receive in the
form of contributions in aid of construction.

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. Currently, depreciation rates on our regulated
interstate system and storage facility vary from 1 to 20 percent. Using these
rates, the remaining depreciable lives of these assets range from 1 to 39 years.

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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, accrued abandonment costs were
$24.6 million, of which $6.4 million was related to offshore wells. As discussed
below, we adopted SFAS No. 143 Accounting for Asset Retirement Obligations on
January 1, 2003 and the amounts accrued and capitalized were 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.

Accounting for Asset Retirement Obligations

On January 1, 2003, we adopted SFAS No. 143. The provisions of this
statement relate primarily to our obligations to plug abandoned offshore wells
that constitute part of our non-segment assets.

Upon our adoption of SFAS No. 143, we recorded (i) a $7.4 million net
increase to property, plant, and equipment, relating to offshore wells,
representing non-current retirement assets, (ii) a $5.7 million increase to
noncurrent liabilities representing retirement obligations, and (iii) a $1.7
million increase to income as a cumulative effect of accounting change. Each
retirement asset is depreciated over the remaining useful life of the long-term
asset with which the retirement liability is associated. An ongoing expense is
recognized for the interest component of the liability due to the changes in the
value of the retirement liability as a result of the passage of time, which we
reflect as a component of depreciation expense in our income statement.

Other than our obligations to plug and abandon wells, 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. We believe that the lives of our assets or the
underlying reserves associated with our assets cannot be estimated. Therefore,
aside from the liability associated with the plugging and abandonment of
offshore wells, we have not recorded liabilities relating to any of our other
assets.

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The pro forma income from continuing operations and amounts per common unit
for the years ended December 31, 2002 and 2001, assuming the provisions of SFAS
No. 143 were adopted prior to the earliest period presented, are shown below:

The pro forma amount of our asset retirement obligations at December 31,
2002 and 2001, assuming asset retirement obligations as provided for in SFAS No.
143 were recorded prior to the earliest period presented was $5.7 million and
$5.3 million. Our asset retirement obligation for December 31, 2003, is shown
below.

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

(1) Abandonment work performed during the year ended December 31, 2003.

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, 2003 and 2002, we had no
goodwill, other than as described below.

As of December 31, 2003 and 2002, 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 it for impairment
if an event occurs that indicates there may be a loss in value, or at least
annually. 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.

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, 2003
and 2002, the value of these intangible assets was approximately $3.4 million
and

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$4.0 million and is reflected on our accompanying consolidated balance sheets as
intangible assets. We amortize the intangible assets acquired in the EPN Holding
asset acquisition to expense using the units-of-production method over the
expected lives of the reserves ranging from 26 to 45 years. We amortize the
intangible assets acquired in the San Juan asset acquisition over the life of
the contracts of approximately 4 years.

Impairment and Disposal of Long-Lived Assets

We apply the provisions of SFAS No. 144 Accounting for the Impairment or
Disposal of Long-Lived Assets to account for impairment and disposal of
long-lived assets. Accordingly, we evaluate the recoverability of 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, less cost to sell, 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 in the
period(s) in which they occur. Upon our adoption of SFAS No. 144, we
reclassified our losses on the sale of long-lived assets of $0.4 million and
$11.4 million for the years ended December 31, 2002 and 2001, into operating
income to conform with the provisions of SFAS No. 144.

We also reclassify the asset or assets as either held for sale or as
discontinued operations, depending on whether they have independently
determinable cash flow and whether we have any continuing involvement.

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, 2003 and 2002, the unamortized amount of our debt issue costs
included in other noncurrent assets was $29.2 million and $32.6 million.
Amortization of debt issue costs for the years ended December 31, 2003, 2002 and
2001 were $7.5 million, $4.4 million and $3.6 million and are included in
interest and debt expense on our consolidated statements of income.

Revenue Recognition and Cost of Natural Gas 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

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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.

Prior to 2002, our cost of natural gas consisted primarily of natural gas
purchased at GulfTerra Alabama Intrastate 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. Beginning in 2003, we
record revenue from these buy/sell transactions upon delivery of the oil based
on the net amount billed to the producers. We acquired the Typhoon oil pipeline
in November 2002, and for the year ended December 31, 2002, we recorded revenue
based on the gross amount billed to the producers. For the year ended December
31, 2002, we reclassified $10.5 million from cost of natural gas and other
products to revenue to conform to our 2003 presentation. This reclassification
has no effect on operating income, net income or partners' capital.

As of July 1, 2003, HIOS implemented new rates, subject to a refund, and we
established a reserve for our estimate of the refund obligation. We will
continue to review our expected refund obligation as the rate case moves through
the hearing process and may increase or decrease the amounts reserved for refund
obligation as our expectation changes.

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 consolidated
balance sheets 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;

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- 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.

We account for all of our derivative instruments in our consolidated
financial statements under SFAS No. 133, Accounting for Derivative Instruments
and Hedging Activities. We record all derivatives in our consolidated balance
sheets 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.

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 2003, 2002 and 2001, we entered into cash flow hedges that qualify
for hedge accounting under 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. At the date of the hedged transaction, 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 or interest expense, as appropriate, 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, or are not documented, 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 through current earnings 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.

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
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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.

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on
Derivative Instruments and Hedging Activities. This statement amends SFAS No.
133 to incorporate several interpretations of the Derivatives Implementation
Group (DIG), and also makes several minor modifications to the definition of a
derivative as it was defined in SFAS No. 133. SFAS No. 149 is effective for
contracts entered into or modified after June 30, 2003. There was no initial
financial statement impact of adopting this standard, although the FASB and DIG
continue to deliberate on the application of the standard to certain derivative
contracts, which may impact our financial statements in the future.

Income Taxes

As of December 31, 2003, neither we nor any of our subsidiaries are taxable
entities. 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.

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 and 2001, 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.

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 GulfTerra Alabama Intrastate operations,
our Indian Basin processing plant, the San Juan assets and our unconsolidated
affiliate, Poseidon Oil Pipeline Company, L.L.C.

The following table presents our allocation of accumulated other
comprehensive loss as of December 31:

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Accounting for Stock-Based Compensation

We use the intrinsic value method established in Accounting Principles
Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees, to value
unit options issued to individuals who are on our general partner's current
board of directors and for those grants made prior to El Paso Corporation's
acquisition of our general partner in August 1998 under our Omnibus Plan and
Director Plan. For the years ending December 31, 2003, 2002 and 2001, the cost
of this stock-based compensation had no impact on our net income, as all options
granted had an exercise price equal to the market value of the underlying common
stock on the date of grant. We use the provisions of SFAS No. 123, Accounting
for Stock-Based Compensation, to account for all of our other stock-based
compensation programs.

In December 2002, the 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 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 issued to individuals who
are on our general partner's current board of directors and for those grants
made prior to El Paso Corporation's acquisition of our general partner in August
1998 and will include data providing the pro forma income effect of using the
fair value method as required by SFAS No. 148. We will continue to use the
provisions of SFAS No. 123 to account for all of our other stock-based
compensation programs.

If compensation expense related to these plans had been determined by
applying the fair value method in SFAS No. 123 our net income allocated to
common unitholders and net income per common unit would have approximated the
pro forma amounts below:

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

Accounting for Debt Extinguishments

In January 2003, we adopted SFAS No. 145, Rescission of FASB Statements No.
4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.
Accordingly, we now evaluate the nature
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of any debt extinguishments to determine whether to report any gain or loss
resulting from the early extinguishment of debt as an extraordinary item or as a
component of income from continuing operations.

Accounting for Costs Associated with Exit or Disposal Activities

In January 2003, we adopted SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities. This statement impacts any exit or disposal
activities that we initiate after January 1, 2003 and we now recognize costs
associated with exit or disposal activities when they are incurred rather than
when we commit to an exit or disposal plan. Our adoption of this pronouncement
did not have an effect on our financial position or results of operations.

Accounting for Guarantees

In accordance with the provisions of Financial Accounting Standards Board
(FASB) Interpretation (FIN) No. 45, Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others, we record a liability at fair value, or otherwise disclose, certain
guarantees issued after December 31, 2002, that contractually require us to make
payments to a guaranteed party based on the occurrence of certain events. We
have not entered into any material guarantees that would require recognition
under FIN No. 45.

Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity. This statement
provides guidance on the classification of financial instruments, as equity, as
liabilities, or as both liabilities and equity. The provisions of SFAS No. 150
are effective for all financial instruments entered into or modified after May
31, 2003, and otherwise is effective at the beginning of the first interim
period beginning July 1, 2003. We adopted the provisions of SFAS No. 150 on July
1, 2003, and our adoption had no material impact on our financial statements.

New Accounting Pronouncements Issued But Not Yet Adopted

Consolidation of Variable Interest Entities

In January 2003, the FASB issued FIN No. 46, Consolidation of Variable
Interest Entities, an Interpretation of ARB No. 51. This interpretation defines
a variable interest entity (VIE) 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 a company to consolidate a VIE if it is allocated
a majority of the entity's losses and/or returns, including fees paid by the
entity. In December 2003, the FASB issued FIN 46-R, which amended FIN No. 46, to
extend its effective date until the first quarter of 2004 for all types of
entities except special purpose entities (SPE's). In addition, FIN No. 46-R also
limited the scope of FIN No. 46 to exclude certain joint ventures of other
entities that meet the characteristics of businesses.

We have no SPE's as defined by FIN Nos. 46 and 46-R. We have evaluated our
joint ventures, unconsolidated subsidiaries and other contractual arrangements
that could be considered variable interests or variable interest entities that
were created before February 1, 2003 and have determined that they will not have
a significant effect on our reported results and financial position when we
adopt the provisions of FIN No. 46-R in the first quarter of 2004.

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2. ACQUISITIONS AND DISPOSITIONS

Merger with Enterprise

On December 15, 2003, we, along with Enterprise and El Paso Corporation,
announced that we had executed definitive agreements to merge Enterprise and
GulfTerra to form one of the largest publicly traded MLPs. The general partner
of the combined partnership will be jointly owned by affiliates of El Paso
Corporation and privately-held Enterprise Products Company, with each owning a
50-percent interest. The definitive agreements include three transactions, of
which two affect us.

In the first transaction that effects us, which occurred with the signing
of the merger agreement, a wholly owned subsidiary of Enterprise purchased a 50
percent limited-voting interest in our general partner. This interest entitles
Enterprise to half of the cash distributed to our general partner, but does not
allow Enterprise to elect any of our general partner's directors or otherwise
generally participate in our general partner's management of our business.

The second transaction that affects us will occur at the merger date. At
the closing of the merger, each outstanding GulfTerra common unit (other than
those owned by Enterprise) will convert into 1.81 Enterprise common units,
GulfTerra will become a wholly-owned subsidiary of Enterprise, and El Paso
Corporation will acquire a 50 percent interest in Enterprise's general partner
(including the right to elect half of the directors of Enterprise's general
partner). The closing of the merger is subject to the satisfaction of specified
conditions, including obtaining clearance under the Hart-Scott-Rodino Antitrust
Improvement Acts, and the approval of our unitholders and Enterprise's
unitholders. Completion of the merger is expected to occur during the second
half of 2004.

Our merger agreement with Enterprise limits our ability to raise additional
capital prior to the closing of the merger without Enterprise's approval. In
addition, because the closing of the merger will be a change of control, and
thus a default, under our credit facility, we will either repay or amend that
facility prior to the closing. In addition, because the merger closing will
constitute a change of control under our indentures, we will be required to
offer to repurchase our outstanding senior subordinated notes (and possibly our
senior notes) at 101 percent of their principal amount after the closing. In
coordination with Enterprise, we are evaluating alternative financing plans in
preparation for the close of the merger. We and Enterprise can agree on the date
of the merger closing after the receipt of all necessary approvals. We do not
intend to close until appropriate financing is in place.

If the merger agreement is terminated and (1) a business transaction
between us and a third party that conflicts with the merger was proposed and
certain other conditions were met or (2) we materially and willfully violated
our agreement not to solicit transactions that conflict with the merger, then we
will be required to pay Enterprise a termination fee of $112 million. If the
merger agreement is terminated because our unitholders did not approve the
merger and either (1) a possible business transaction involving us but not
involving Enterprise and conflicting with the merger was publicly proposed and
our board of directors publicly and timely reaffirmed its recommendations of the
Enterprise merger or (2) no such possible business transaction was publicly
announced, then we will be required to pay Enterprise a termination fee of $15
million. Enterprise is subject to similar termination fee requirements.

Exchange with El Paso Corporation

In connection with our November 2002 San Juan assets acquisition, El Paso
Corporation retained the obligation to repurchase the Chaco plant from us for
$77 million in October 2021. In October 2003, we released El Paso Corporation
from that obligation in exchange for El Paso Corporation contributing specified
communication assets and other rights to us. The communication assets we
received are used in the operation of our pipeline systems. Prior to the October
2003 exchange, we had access to these assets under our general

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and administrative services agreement with El Paso Corporation. We recorded the
communication assets at El Paso Corporation's book value of $23.3 million with
the offset to partners' capital.

As a result of the October 2003 exchange, we revised our estimate for the
depreciable life of the Chaco plant from 19 to 30 years, the estimated remaining
useful life of the Chaco plant. Depreciation expense will decrease approximately
$0.5 million and $2.3 million on a quarter and annual basis.

Cameron Highway Oil Pipeline Company

Refer to Note 3 for a discussion related to our sale of a 50 percent
interest in Cameron Highway Oil Pipeline.

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 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, $764 million after
adjustments for capital expenditures and actual working capital acquired. During
2003, the total purchase price and net assets acquired decreased $2.4 million
due to post-closing purchase price adjustments related to natural gas
imbalances, NGL in-kind reserves and well loss reserves. 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 10,937,500 of our Series C units valued at $32 per unit or $350 million; 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, we entered into an agreement with El
Paso Corporation under which El Paso Corporation would have been required,
subject to specified conditions, to repurchase the Chaco plant from us for $77
million in October 2021, at which time we would have had the right to lease the
plant from them for a period of 10 years with the option to renew the lease
annually thereafter. In October 2003, we

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released El Paso Corporation from that repurchase obligation in exchange for El
Paso Corporation contributing communication assets to us.

As a result of our acquisition of the San Juan assets, our financial
results from the operation of the Chaco plant are significantly different from
our results prior to the purchase in the following ways:

- 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, accordingly, 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.

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 acquired intangible assets represent contractual rights we obtained
under dedication and transportation agreements with producers which we are
amortizing to expense over the life of the contracts of approximately 4 years.
We recorded adjustments to the purchase price of approximately $18 million
primarily for capital expenditures and actual working capital 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

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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.

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, for purposes of these
financial statements, 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.

- GulfTerra Texas Pipeline, L.P. which owned, among other assets, (i) the
GulfTerra 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 owned 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 owned, 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 owned 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

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of $15 million of net working capital obligations 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).

During 2003, the purchase price and net assets acquired increased $17.5
million due to post-closing purchase price adjustments related primarily to a
reduction in natural gas imbalance payables assumed in the transaction.

We 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.

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 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 GulfTerra Texas intrastate pipeline assets
as discussed in Note 11.

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
GulfTerra 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

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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:

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.

Prince Assets

In connection with our April 2002 acquisition of the EPN Holding assets
from El Paso Corporation, we sold our Prince tension leg platform (TLP) and our
nine percent overriding royalty interest in the Prince Field to subsidiaries of
El Paso Corporation. The results of operations for these assets have been
accounted for as discontinued operations and have been excluded from continuing
operations for all periods in our consolidated statements of income.
Accordingly, the segment results in Note 15 reflect neither the results of
operations for the Prince assets nor the related net assets held for sale. The
Prince TLP was previously included in the platform services segment and related
royalty interest was included in non-segment activity. Included in income from
discontinued operations for the years ended December 31, 2002 and 2001 were
revenues of $7.8 million and $8.8 million attributable to these disposed assets.

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 interests in the title
holder of, and other interests in 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

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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 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.

GTM Texas (formerly EPN Texas)

In February 2001, we acquired GTM 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 GTM
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 year ended
December 31, 2001, as if we acquired GTM Texas, the Chaco plant and the
remaining 50 percent interest in Deepwater Holdings on January 1, 2001:

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

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was approximately $14 million, which has been reflected in earnings from
unconsolidated affiliates in the accompanying 2001 consolidated statement of
income.

As additional consideration for the above transactions, El Paso Corporation
agreed to make payments to us totaling $29 million. These payments were made in
quarterly installments of $2.25 million for three years beginning in 2001 and we
will receive the final payment of $2 million 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 2001 consolidated statement of income.

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, 2003, 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 recorded adjustments primarily for differences from estimated earnings
reported in our Annual Report on our Form 10-K and actual earnings reported
in the unaudited financial statements of our unconsolidated affiliates.

(b) Total earnings from unconsolidated affiliates includes a $898 thousand gain
associated with the sale of our interest in Copper Eagle.

(c) Cameron Highway Oil Pipeline Company and Deepwater Gateway, L.L.C. are
development stage companies; therefore there are no operating revenues or
operating expenses to provide operational results. Since their formations,
they have incurred organizational expenses and received interest income.

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Cameron Highway. In June 2003, we formed Cameron Highway Oil Pipeline
Company and contributed to this newly formed company the $458 million Cameron
Highway oil pipeline system construction project. Cameron Highway is responsible
for building and operating the pipeline, which is scheduled for completion
during the fourth quarter of 2004. We entered into producer agreements with
three major anchor producers, BP Exploration & Production Company, BHP Billiton
Petroleum (Deepwater), Inc., and Union Oil Company of California, which
agreements were assigned to and assumed by Cameron Highway. The producer
agreements require construction of the 390-mile Cameron Highway oil pipeline.

In July 2003, we sold a 50 percent interest in Cameron Highway to Valero
Energy Corporation for $86 million, forming a joint venture with Valero. Valero
paid us approximately $70 million at closing, including $51 million representing
50 percent of the capital investment expended through that date for the pipeline
project. In July 2003, we recognized $19 million as a gain from the sale of
long-lived assets. In addition, Valero will pay us $5 million once the system is
completed and another $11 million by the end of 2006. We expect to reflect the
receipts of these additional amounts in the periods received as gains from the
sale of long-lived assets in our statement of income. In connection with the
formation of the Cameron Highway joint venture, Valero agreed to pay their
proportionate share of pipeline construction costs that exceed Cameron Highway's
capital resources, including the initial equity contributions and proceeds from
Cameron Highway's project loan facility.

The Cameron Highway oil pipeline system project is expected to be funded
with 37 percent equity, or $169 million through capital contributions from us
and Valero, the two Cameron Highway partners, which contributions have already
been made, and 63 percent debt through a $325 million project loan facility,
consisting of a $225 million construction loan and $100 million of senior
secured notes. See Note 6 for additional discussion of the project loan
facility. As of December 31, 2003, Cameron Highway has spent approximately $256
million (of which $85 million constituted equity contributions by us) related to
this pipeline, which is in the construction stage. We and Valero are obligated
to make additional capital contributions to Cameron Highway if and to the extent
that the construction costs for the pipeline exceed Cameron Highway's capital
resources, including initial equity contributions and proceeds from Cameron
Highway's project loan facility.

Deepwater Gateway. As of December 31, 2003, we have contributed $33
million, as our 50 percent share, to Deepwater Gateway, which amount satisfies
our initial equity 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 and Deepwater Gateway's members'
contingent equity obligations (of which our share is $14 million). 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.

Front Runner Oil Pipeline. In September 2003, we announced that Poseidon,
our 36 percent owned joint venture, entered into an agreement for the purchase
and sale of crude oil from the Front Runner Field. Poseidon will construct, own
and operate the $28 million project, which will connect the Front Runner
platform with Poseidon's existing system at Ship Shoal Block 332. The new
36-mile, 14-inch pipeline is expected to be operational by the third quarter of
2004 and have a capacity of 65 MBbls/d. As Poseidon expects to fund Front
Runner's capital expenditures from its operating cash flow and from its
revolving credit

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facility, we do not expect to receive distributions from Poseidon until the
Front Runner oil pipeline is completed.

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

(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, from the acquisition
date 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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4. PROPERTY, PLANT AND EQUIPMENT

Our property, plant and equipment consisted of the following:

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

(1) Includes leasehold acquisition costs with an unamortized balance of $3.2
million and $4.1 million at December 31, 2003 and 2002. One interpretation
being considered relative to SFAS No. 141, Business Combinations and SFAS
No. 142, Goodwill and Intangible Assets is that oil and gas mineral rights
held under lease and other contractual arrangements representing the right
to extract such reserves for both undeveloped and developed leaseholds
should be classified separately from oil and gas properties, as intangible
assets on our consolidated balance sheets. We will continue to include these
costs in property, plant, and equipment until further guidance is provided.

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. 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. 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. As part of
the San Juan acquisition, the processing agreement was terminated.

6. FINANCING TRANSACTIONS

CREDIT FACILITY

Our credit facility consists of two parts: the revolving credit facility
maturing in 2006 and a senior secured term loan maturing in 2008. Our credit
facility is guaranteed by us and all of our subsidiaries, except for our
unrestricted subsidiaries, as detailed in Note 16, and are collateralized with
substantially all of our assets (excluding the assets of our unrestricted
subsidiaries). The interest rates we are charged on our credit facility are
determined at our option using one of two indices that include (i) a variable
base rate (equal to the greater of the prime rate as determined by JPMorgan
Chase Bank, the federal funds rate plus 0.5% or the Certificate of Deposit (CD)
rate as determined by JPMorgan Chase Bank increased by 1.00%); or (ii) LIBOR.
The interest rate we are charged is contingent upon our leverage ratio, as
defined in our credit facility, and ratings we are assigned by S&P or Moody's.
The interest we are charged would increase by 0.25% if the credit ratings

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on our senior secured credit facility decrease or our leverage ratio decreases,
or, alternatively, would decrease by 0.25% if these ratings are increased or our
leverage ratio improves. Additionally, we pay commitment fees on the unused
portion of our revolving credit facility at rates that vary from 0.30% to 0.50%.

Our credit facility contains 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 our credit facility are as
follows:

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

(b) 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

(c) The ratio of our consolidated total 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 5.25 to 1.0.

Among other things, our credit agreement includes as an event of default a
change of control, defined as the failure of El Paso Corporation and its
subsidiaries to no longer own at least 50 percent of our general partner. We are
in compliance with the financial ratios and covenants contained in each of our
credit facilities at December 31, 2003.

Revolving Credit Facility

In September 2003, we renewed our revolving credit facility to, among other
things, expand the credit available from $600 million to $700 million and extend
the maturity from May 2004 to September 2006.

At December 31, 2003, we had $382 million outstanding under our revolving
credit facility at an average interest rate of 3.17%. We may elect that all or a
portion of the revolving credit facility bear interest at either the variable
rate described above increased by 1.0% or LIBOR increased by 2.0%. The total
amount available to us at December 31, 2003, under this facility was $318
million.

Senior Secured Term Loan

In December 2003, we refinanced the term loan portion of our credit
facility to provide greater financial flexibility by, among other things,
expanding the existing term component from $160 million to $300 million,
extending the maturity from October 2007 to December 2008, reducing the
semi-annual payments from $2.5 million to $1.5 million and reducing the interest
rate we are charged by 1.25%. We used the proceeds from the term loan to repay
the $155 million outstanding under the initial term loan and to temporarily
reduce amounts outstanding under our revolving credit facility. We charged $2.8
million to interest and debt expense in December 2003 to write-off unamortized
debt issuance costs associated with the initial term loan.

The senior secured term loan is payable in semi-annual installments of $1.5
million in June and December of each year for the first nine installments and
the remaining balance at maturity in December 2008. We may elect that all or a
portion of the senior secured term loan bear interest at either 1.25% over the
variable base rate discussed above; or LIBOR increased by 2.25%. As of December
31, 2003, we had $300 million outstanding with an average interest rate of
3.42%.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

GulfTerra Holding Term Credit Facility (formerly 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 credit facility provided a
term loan (the GulfTerra Holding term loan) of $535 million to finance the
acquisition of the EPN Holding assets, and a revolving credit facility (the
GulfTerra Holding revolving credit facility) of up to $25 million to finance EPN
Holding's working capital. 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 GulfTerra Holding revolving credit facility. 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. In July 2003, we repaid the remaining $160 million balance
of this term credit facility with proceeds from our issuance of $250 million
6 1/4% senior notes due 2010. We recognized a loss of $1.2 million related to
the write-off of unamortized debt issuance costs in connection with our
repayment of this facility.

Senior Secured Acquisition Term Loan

As part of our November 2002 San Juan assets acquisition, we entered into a
$237.5 million senior secured acquisition term loan to fund a portion of the
purchase price. We repaid this senior secured acquisition term loan in March
2003 with proceeds from our issuance of $300 million 8 1/2% senior subordinated
notes due 2010. We recognized a loss of $3.8 million related to the write-off of
unamortized debt issuance costs in connection with our repayment of this
facility. From the issuance of the senior secured acquisition term loan in
November 2002 to its repayment date, the interest rates on our revolving credit
facility and GulfTerra Holding term credit facility were 2.25% over the variable
base rate described above or LIBOR increased by 3.50%.

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 assets acquisition.

SENIOR NOTES

In July 2003, we issued $250 million in aggregate principal amount of
6 1/4% senior notes due June 2010. We used the proceeds of approximately $245.1
million, net of issuance costs, to repay $160 million of indebtedness under the
GulfTerra Holding term credit facility and to temporarily repay $85.1 million of
the balance outstanding under our revolving credit facility. The interest on our
senior notes is payable semi-annually in June and December with the principal
maturing in June 2010. Our senior notes are unsecured obligations that rank
senior to all our existing and future subordinated debt and equally with all of
our existing and future senior debt, although they are effectively junior in
right of payment to all of our existing and future senior secured debt to the
extent of the collateral securing that debt. Our senior notes are guaranteed by
us and all of our subsidiaries, except for our unrestricted subsidiaries.

We may redeem some or all of our senior notes, at our option, at any time
with at least 30 days notice at a price equal to the greater of (1) 100 percent
of the principal amount plus accrued interest, or (2) the sum of the present
value of the remaining scheduled payments plus accrued interest.

SENIOR SUBORDINATED NOTES

Each issue of our senior subordinated notes is subordinated in right of
payment to all of our existing and future senior debt, including our existing
credit facility and the senior notes we issued in July 2003.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In March 2003, we issued $300 million in aggregate principal amount of
8 1/2% senior subordinated notes. The interest on these notes is payable
semi-annually in June and December, and the notes mature in June 2010. We used
the proceeds of approximately $293.5 million, net of issuance costs, to repay
$237.5 million of indebtedness under our senior secured acquisition term loan
and to temporarily repay $55.5 million of the balance outstanding under our
revolving credit facility. We may, at our option, prior to June 1, 2006, redeem
up to 33 percent of the originally issued aggregate principal amount of these
notes at a redemption price of 108.50 percent of the principal amount, and in
December 2003, we redeemed $45 million under this provision (see discussion
below). We may redeem all or part of the remainder of these notes at any time on
or after June 1, 2007. The redemption price on that date is 104.25 percent of
the principal amount, declining annually until it reaches 100 percent of the
principal amount.

In November 2002, we issued $200 million in aggregate principal amount of
10 5/8% Senior Subordinated Notes. The interest on these notes is 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. 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%, and in December
2003, we redeemed $66 million under this provision (see discussion below). On or
after December 1, 2007, we may redeem all or part of the remainder 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. The interest on these notes is 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%, and in December 2003, we
redeemed $75.9 million under this provision (see discussion below). On or after
June 1, 2006, we may redeem all or part of the remainder 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. The interest on these notes is 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 redemption price of 108.500%, and
in December 2003, we redeemed $82.5 million under this provision (see discussion
below). On or after June 1, 2006, we may redeem all or part of the remainder 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. The interest on these notes is 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 GulfTerra Energy Partners Finance Corporation and
our unrestricted subsidiaries, have guaranteed our obligations under the senior
notes and all of the issuances of senior subordinated notes described above. In
addition, we could be required to repurchase the senior notes and senior
subordinated notes if certain circumstances relating to change of control or
asset dispositions exist.

In July 2003, to achieve a better mix of fixed rate debt and variable rate
debt, we entered into an eight-year interest rate swap agreement to provide for
a floating interest rate on $250 million of our 8 1/2%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

senior subordinated notes due 2011. With this swap agreement, we will pay the
counterparty a LIBOR based interest rate plus a spread of 4.20% (which rate was
1.55% at December 31, 2003) and receive a fixed rate of 8 1/2%. We are
accounting for this derivative as a fair value hedge under SFAS No. 133. At
December 31, 2003, the fair value of the swap was a liability, included in
non-current liabilities, of approximately $7.4 million. The fair value of the
hedged debt decreased by the same amount.

In December 2003, we used a portion of the net proceeds from our October
2003 equity offerings to redeem approximately $269.4 million in principal amount
of our senior subordinated notes. The terms of our indentures allow us to use
proceeds from an equity offering, within a 90 day period after the offering, to
redeem up to 33 percent of the principal during the first three years the notes
are outstanding. We incurred additional costs totaling $29.1 million resulting
from the payment of the redemption premiums and the write-off of unamortized
debt issuance costs, premiums and discounts. We accounted for these costs as an
expense during the fourth quarter of 2003 in accordance with the provisions of
SFAS No. 145.

In March 2004, we gave notice to exercise our right, under the terms of our
senior subordinated notes' indentures, to repay, at a premium, approximately
$39.1 million in principal amount of those senior subordinated notes. The
indentures provide that, within 90 days of an equity offering, we can call up to
33 percent of the original face amount at a premium. The amount we can repay is
limited to the net proceeds of the offering. We will recognize additional costs
totaling $4.1 million resulting from the payment of the redemption premiums and
the writeoff of unamortized debt issuance costs. We will account for these costs
as an expense during the second quarter of 2004 in accordance with the
provisions of SFAS No. 145.

RESTRICTIVE PROVISIONS OF SENIOR AND SENIOR SUBORDINATED NOTES

Our senior and senior subordinated notes include provisions that, among
other things, restrict our ability and the ability of our subsidiaries
(excluding our unrestricted subsidiaries) to incur additional indebtedness or
liens, sell assets, make loans or investments, acquire or be acquired by other
companies, and enter into sale and lease-back transactions, as well as requiring
maintenance of certain financial ratios. Failure to comply with the provisions
of these covenants could result in acceleration of our debt and other financial
obligations and that of our subsidiaries in addition to restricting our ability
to make distributions to our unitholders. Many restrictive covenants associated
with our senior notes will effectively be removed following a period of 90
consecutive days during which they are rated Baa3 or higher by Moody's or BBB-
or higher by S&P, and some of the more restrictive covenants associated with
some (but not all) of our senior subordinated notes will be suspended should
they be similarly rated.

OTHER CREDIT FACILITIES

Poseidon

As of December 31, 2003, Poseidon Oil Pipeline Company, L.L.C., an
unconsolidated affiliate in which we have a 36 percent joint venture ownership
interest, was party to a $185 million credit agreement under which it had $123
million outstanding at December 31, 2003.

In January 2004, Poseidon amended its credit agreement and decreased the
availability to $170 million. The amended facility matures in January 2008. The
outstanding balance from the previous facility was transferred to the new
facility.

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
$123 million outstanding under its credit facility at 3.49% through January
2004. Poseidon, under its credit facility, currently pays an additional 1.25%
over the LIBOR rate resulting in an effective interest rate of 4.74% on the
hedged notional amount. The interest rates Poseidon is charged on balances
outstanding under its credit facility are dependent on its leverage ratio as
defined in the Poseidon credit facility. Poseidon's interest rate at December
31, 2003 was LIBOR plus 1.25% for Eurodollar
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 0.25% for Base Rate loans. As of December 31, 2003, the
remaining $48 million was at an average interest rate of 2.46%.

Under its amended credit facility, based on Poseidon's leverage ratio for
the year ended December 31, 2003, Poseidon's interest rate is LIBOR plus 2.00%
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 1.00% for Base Rate loans. Poseidon's interest
rates will decrease by 0.25% if their leverage ratio declines to 3.00 to 1.00 or
less, by 0.50% if their leverage ratio declines to 2.00 to 1.00 or less, or by
0.625% 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 times the previous quarters'
interest.

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 $170 million 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

(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 4.50 to 1.00 in 2004, 3.50 to 1.00 in 2005 and 3.00 to 1.00
thereafter.

Poseidon was in compliance with the above covenants and the covenants under
its previous facility as of December 31, 2003.

Deepwater Gateway

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, 2003, Deepwater Gateway had $155 million
outstanding under the project finance loan at an average interest rate of 2.94%
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,
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GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Deepwater Gateway is prohibited from making distributions until the project
finance loan has been repaid or is converted.

Cameron Highway

Cameron Highway Oil Pipeline Company (Cameron Highway), an unconsolidated
affiliate in which we have a 50 percent joint venture ownership interest (See
Note 3 for additional discussion relating to the formation of Cameron Highway),
entered into a $325 million project loan facility, consisting of a $225 million
construction loan and $100 million of senior secured notes, each of which fund
proportionately as construction costs are incurred.

The $225 million construction loan bears interest at Cameron Highway's
option at each borrowing at either (i) 2.00% over the variable base rate (equal
to the greater of the prime rate as determined by JPMorgan Chase Bank, the
federal funds rate plus 0.5% or the Certificate of Deposit (CD) rate as
determined by JPMorgan Chase Bank increased by 1.00%); or (ii) 3.00% over LIBOR.
Upon completion of the construction, the construction loan will convert to a
term loan maturing July 2008, subject to the terms of the loan agreement. At the
end of the first quarter following the first anniversary of the conversion into
a term loan, Cameron Highway will be required to make quarterly principal
payments of $8.125 million, with the remaining unpaid principal amount payable
on the maturity date. If the construction loan fails to convert into a term loan
by December 31, 2006, the construction loan and senior secured notes become
fully due and payable. At December 31, 2003, Cameron Highway had $69 million
outstanding under the construction loan at an average interest rate of 4.21%.

The interest rate on Cameron Highway's senior secured notes is 3.25% over
the rate on 10-year U.S. Treasury securities. Principal payments of $4 million
are due quarterly from September 2008 through December 2011, $6 million each
from March 2012 through December 2012, and $5 million each from March 2013
through the principal maturity date of December 2013. At December 31, 2003,
Cameron Highway had $56 million outstanding under the notes at an average
interest rate of 7.38%.

Under the terms of its project loan facility, Cameron Highway must pay each
of the lenders and the senior secured noteholders commitment fees of 0.5% per
year on any unused portion of such lender's or noteholder's committed funds. The
project loan facility as a whole is collateralized by (1) substantially all of
Cameron Highway's assets, including, upon conversion, a debt service reserve
capital account, and (2) all of the equity interest in Cameron Highway. Other
than the pledge of our equity interest and our construction obligations under
the relevant producer agreements, as discussed in Note 3, the debt is
non-recourse to us. The construction loan and senior secured notes prohibit
Cameron Highway from making distributions to us until the construction loan is
converted into a term loan and Cameron Highway meets certain financial
requirements.

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):

2004...................................................... $ 3,000
2005...................................................... 3,000
2006...................................................... 385,000
2007...................................................... 3,000
2008...................................................... 288,000
Thereafter.................................................. 1,135,600
----------
Total long-term debt and other financing
obligations, including current maturities........ $1,817,600
==========

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

INTEREST AND DEBT EXPENSE

We recognized the interest cost incurred in connection with our financing
transactions as follows for each of the years ended December 31:

LOSS DUE TO EARLY REDEMPTIONS OF DEBT

We recognized losses associated with early redemptions of debt as follows
for each of the years ended December 31:

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:

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

(1) Excludes market value of interest rate swap, see interest rate swap
discussion below.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

In July 2003, we entered into an eight-year interest rate swap agreement to
provide for a floating interest rate on $250 million of our 8 1/2% senior
subordinated notes due 2011. With this swap agreement, we will pay the
counterparty a LIBOR based interest rate plus a spread of 4.20% (which rate was
1.55% at December 31, 2003) and receive a fixed rate of 8 1/2%.

As of December 31, 2003, and 2002, 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.

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, 2003, we had 58,404,649 common units outstanding. Common
units totaling 48,020,404 are owned by the public, representing an 82.2 percent
common unit interest in us. As of December 31, 2003, El Paso Corporation,
through its subsidiaries, owned 10,384,245 common units, or 17.8 percent of our
outstanding common units, all of our 10,937,500 Series C units and 50 percent of
our one percent general partner interest.

Offering of Common Units

During 2003, we issued the following common units in public offerings:

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

(1) Offering includes 80 Series F convertible units offered. Refer to
description below.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In addition to our public offerings of common units, in October 2003, we
sold 3,000,000 common units privately to Goldman Sachs in connection with their
purchase of a 9.9 percent membership interest in our general partner. We used
the net proceeds of $111.5 million from that private sale and the net proceeds
from the other common unit public offerings to temporarily reduce amounts
outstanding under our revolving credit facility, senior subordinated notes, and
for general partnership purposes.

In May 2003, we issued 1,118,881 common units and 80 Series F convertible
units in a registered offering to a large institutional investor for
approximately $38.3 million net of offering costs. Our Series F convertible
units are not listed on any securities exchange or market. Each Series F
convertible unit is comprised of two separate detachable units -- a Series F1
convertible unit and a Series F2 convertible unit -- that have identical terms
except for vesting and termination dates and the number of underlying common
units into which they may be converted. The Series F1 units are convertible into
up to $80 million of common units anytime after August 12, 2003, and until the
date we merge with Enterprise (subject to other defined extension rights). The
Series F2 units are convertible into up to $40 million of common units. The
Series F2 units terminate on March 30, 2005 (subject to defined extension
rights). The price at which the Series F convertible units may be converted to
common units is equal to the lesser of (i) the prevailing price (as defined
below), if the prevailing price is equal to or greater than $35.75, or (ii) the
prevailing price minus the product of 50 percent of the positive difference, if
any, of $35.75 minus the prevailing price. The prevailing price is equal to the
lesser of (i) the average closing price of our common units for the 60 business
days ending on and including the fourth business day prior to our receiving
notice from the holder of the Series F convertible units of their intent to
convert them into common units; (ii) the average closing price of our common
units for the first seven business days of the 60 day period included in (i); or
(iii) the average closing price of our common units for the last seven days of
the 60 day period included in (i). The price at which the Series F convertible
units could have been converted to common units, assuming we had received a
conversion notice on December 31, 2003 and March 2, 2004, was $40.38 and $39.40.
The Series F convertible units may be converted into a maximum of 8,329,679
common units. Holders of Series F convertible units are not entitled to vote or
receive distributions. The $4.1 million value associated with the Series F
convertible units is included in partners' capital as a component of common
units capital.

In August 2003, we amended the terms of the Series F convertible units to
permit the holder to elect a "cashless" exercise -- that is, an exercise where
the holder gives up common units with a value equal to the exercise price rather
than paying the exercise price in cash. If the holder so elects, we have the
option to settle the net position by issuing common units or, if the settlement
price per unit is above $26.00 per unit, paying the holder an amount of cash
equal to the market price of the net number of units. These amendments had no
effect on the classification of the Series F convertible units on the balance
sheet at December 31, 2003.

In the first quarter of 2004, 45 Series F1 convertible units were converted
into 1,146,418 common units, for which the holder of the convertible units paid
us $45 million.

Any Series F convertible units outstanding at the merger date will be
converted into rights to receive Enterprise common units, subject to the
restrictions governing the Series F units. The number of Enterprise common units
and the price per unit at conversion will be adjusted based on the 1.81 exchange
ratio.

In connection with the offerings in 2003, our general partner contributed
to us approximately $2.0 million of our Series B preference units and cash of
$3.1 million in order to maintain its one percent general partner interest.

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)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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. In October 2003, we
redeemed all 123,865 of our remaining outstanding Series B preference units for
$156 million, a 7 percent discount from their liquidation value of $167 million.
For this redemption, we used borrowings under our revolving credit facility. We
reflected the discount as an increase to the common units capital, Series C
units capital and to our general partner's capital accounts.

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
has 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. The holder of the Series C
units has thus far not requested a vote to convert the Series C units into
common units. As part of the proposed merger with Enterprise, Enterprise will
purchase from a subsidiary of El Paso Corporation all of our outstanding Series
C units. These units will not be converted to Enterprise common units in the
merger but rather will remain

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limited partnership interests in GulfTerra after the closing of the merger
transaction and, as such interest, will lose their GulfTerra common unit
conversion and distribution rights.

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.

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 distributions paid to our
common unitholders, Series C unitholder and general partner during the year
ended December 31, 2003:

In January 2004, we declared a cash distribution of $0.71 per common and
Series C unit, $49.3 million in aggregate, for the quarter ended December 31,
2003, which we paid on February 14, 2004. In addition, we paid our general
partner $21.3 million related to its general partner interest. At the current
distribution rates, our general partner receives approximately 30.2 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. During 2003, under our Omnibus Plan, we
granted 17,500 unit options, 25,000 time-vested restricted units and will grant
25,000 restricted units, if certain performance targets are achieved, to
employees of El Paso Field Services whose primary responsibilities are the
commercial management of our assets.

In August 1998, we also adopted the 1998 Common Unit Plan for Non-Employee
Directors (Director Plan), formerly the 1998 Unit Option Plan for Non-Employee
Directors, to provide our general partner with the ability to issue unit options
to attract and retain the services of knowledgeable directors. Unit

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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. During 2003,
under the Director Plan, we granted 5,226 restricted units at a fair value per
unit of $36.37 and 10,500 unit options with a grant price of $35.92. Restricted
units awards representing 5,429 and 4,090 were granted during 2002 and 2001 with
a fair value of $32.23 and $33.00 per unit. As of December 31, 2003, 12,292
restricted units were outstanding.

We have accounted for all of these unit options and restricted units,
except for the unit options issued to non-employee directors, in accordance with
SFAS No. 123. Under SFAS No. 123, we report the fair value of these issuances as
deferred compensation. Deferred compensation is amortized to compensation
expense over the respective vesting or performance period. We have accounted for
the unit options issued to the non-employee directors of our general partner's
Board of Directors in accordance with APB No. 25.

We issued time-vested restricted units and the performance-based restricted
units at fair value at their date of grant. The restrictions on the time-vested
units will lapse in four years from the date of grant. The restrictions on the
performance-based restricted units will lapse if we achieve a specified level of
target performance for identified "greenfield" projects by June 1, 2007 (for the
15,000 performance-based restricted units issued in June 2003) and by August 1,
2007 (for the 10,000 performance-based restricted units issued in August 2003).
If we do not reach those targets by the applicable dates, the performance-based
units will be forfeited. We will amortize the fair value of the time-vested
restricted units over their four-year restricted period and the fair value of
the performance-based restricted units over their performance periods. The
performance-based restricted units are not entitled to vote or to receive
distributions, until after (and if) we achieve specified level of target
performance. The restricted units issued to non-employee directors of our
general partner's Board of Directors were issued at fair value at their date of
grant. This fair value is being amortized to compensation expense over the
period of service, which we have estimated to be one year.

Total unamortized deferred compensation as of December 31, 2003 and 2002
was approximately $1.5 million and $1.2 million. Our 2001 deferred compensation
is fully amortized. Deferred compensation is reflected as a reduction of
partners' capital and is allocated 1 percent to our general partner and 99
percent to our limited partners.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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,
2003, 2002 and 2001.

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
2003, 2002, and 2001 was $3.55, $3.71, and $2.62 per unit option, respectively.

Options outstanding as of December 31, 2003, are summarized below:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

9. EARNINGS PER COMMON UNIT

The following table sets forth the computation of basic and diluted
earnings per common unit (in thousands, except for unit amounts):

10. 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 of
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 Corporation subsidiaries and, in turn,
they provide us services. In addition, we have acquired a number of assets from
subsidiaries of El Paso Corporation. We have not had any material transactions
with Enterprise, other than the merger agreement transactions, since Enterprise
acquired 50 percent of our general partner.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table provides summary data 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, 2003, 2002 and 2001, revenues received
from related parties consisted of approximately 13%, 43% and 28% of our revenue
from continuing operations. Also, we have undertaken efforts to reduce our
transactions with El Paso Merchant Energy North America Company (Merchant
Energy) and as of June 30, 2003, we replaced all our month-to-month arrangements
that were previously with Merchant Energy with similar arrangements with third
parties.

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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 our general partner.
For the years ended December 31, 2003 and 2002, we received $26.5 million and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

$68.9 million from El Paso Merchant Energy North America Company, $19.9 million
and $35.8 million from El Paso Field Services and $3.4 million and $4.0 million
from El Paso Production Company.

GTM Texas. In connection with our acquisition of GTM 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, 2003, 2002 and 2001, we
received revenue of approximately $21.5 million, $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 in November 2002, 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 and 2001 we received
approximately $0.1 million and $1.6 million from El Paso Merchant Energy North
America Company for natural gas storage fees. For the year ended December 31,
2001 we received approximately $0.7 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. 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 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

subsidiaries of El Paso Corporation and these revenues are reflected in our
income from discontinued operations.

GulfTerra Alabama Intrastate. Several El Paso Corporation subsidiaries buy
and transport natural gas on our GulfTerra Alabama Intrastate system. For the
years ended December 31, 2003, 2002 and 2001, we received approximately $0.7
million, $6.8 million and $8.3 million from El Paso Merchant Energy North
America Company. For the years ended December 31, 2003, 2002 and 2001, we
received approximately $4.5 million, $4.5 million and $4.2 million from El Paso
Production Company. For the years ended December 31, 2003, 2002 and 2001, we
received approximately $0.1 million, $0.1 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 years
ended December 31, 2003 and 2002 and approximately three months ended December
31, 2001, we received $0.1 million, $1.4 million and $0.8 million from El Paso
Merchant Energy. For the year ended December 31, 2003 and 2002, we received $1.2
million and $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 $7.5 million and
$0.3 million in revenues from El Paso Field Services for the years ended
December 31, 2003 and 2002.

Other. In addition to the revenues discussed above, we received $2.8
million and $2.6 million from El Paso Merchant North America and $25.6 million
and $3.3 million from El Paso Field Services during 2003 and 2002 for additional
gathering and processing services. The 2003 increase in revenues for El Paso
Field Services was primarily as a result of higher natural gas prices and NGL
volumes sold to El Paso Field Services from our Big Thicket assets.

Unconsolidated Subsidiaries. For the years ended December 31, 2001 we
received approximately $0.03 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 2003 and 2002 as a result of our San Juan assets acquisitions and
our EPN Holding transaction in which we acquired contracts with affiliates of
our general partner. For the year ended December 31, 2003, our San Juan assets
had cost of natural gas expenses of $1.3 million from El Paso Merchant Energy
North America and $0.3 million from El Paso Field Services. For the year ended
December 31, 2003 and 2002, our EPN Holding assets had cost of natural gas
expenses of $0.9 million and $0.3 million from El Paso Merchant Energy North
America Company and $3.5 million and $0.4 million from El Paso Field Services
relating to the GulfTerra Texas gathering system. GulfTerra Alabama Intrastate's
purchases of natural gas include transactions with affiliates of our general
partner. For the years ended December 31, 2003, 2002 and 2001, we had natural
gas purchases of approximately $25.6 million, $18.9 million and $28.2 million
from El Paso Merchant Energy North America Company, and $0.1 million, $0.2
million and $0.2 million from Southern Natural Gas Company and $2.3 million and
$6.4 million from El Paso Production Company for the years ended December 31,
2002 and 2001. We also receive lease and throughput fees from El Paso Field
Services for Hattiesburg and Anse

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

La Butte. For the year ended December 31, 2002 we received $0.5 million from El
Paso Field Services related to these fees.

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 2002 to 2003 and from 2001 to 2002 due to the
acquisition of the San Juan assets and EPN Holding assets.

Cost Reimbursements. In connection with becoming the operator of Poseidon,
we entered into an operating agreement in January 2001. All fees received under
contracts approximate actual costs incurred.

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 11,
Commitments and

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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 have made claims for approximately $5 million for costs incurred
during the year ended December 31, 2003 as costs exceeded the established
thresholds for the year ended December 31, 2003.

We have also entered into capital contribution arrangements with entities
owned by El Paso Corporation, including its regulated pipelines, in the past,
and will most likely do so in the future, as part of our normal commercial
activities in the Gulf of Mexico. We have an agreement to receive $6.1 million,
of which $3.0 million has been collected, from ANR Pipeline Company for our
Phoenix project. As of December 31, 2003, we have received $10.5 million from
ANR Pipeline and $7.0 million from El Paso Field Services for the Marco Polo
natural gas pipeline. In October 2003, we collected $2 million from Tennessee
Gas Pipeline for our Medusa project. These amounts are reflected as a reduction
in project costs. Regulated pipelines often contribute capital toward the
construction costs of gathering facilities owned by others which are, or will
be, connected to their pipelines. El Paso Field Services' contribution is in
anticipation of additional natural gas volumes that will flow through to its
onshore natural gas processing facilities.

In August 2003, Arizona Gas Storage L.L.C., along with its 50 percent
partner APACS Holdings L.L.C., sold their interest in Copper Eagle Gas Storage
L.L.C. to El Paso Natural Gas Company (EPNG), a subsidiary of El Paso
Corporation. Copper Eagle Gas Storage is developing a natural gas storage
project located outside of Phoenix, Arizona. Arizona Gas Storage is an indirect
60 percent owned subsidiary of us and 40 percent owned by IntraGas US, a Gaz de
France North American subsidiary. APACS Holdings L.L.C. is a wholly owned
subsidiary of Pinnacle West Energy, a subsidiary of Pinnacle West Capital
Corporation. We have the right to receive $6.2 million of the sale proceeds,
including a note receivable for $4.9 million to be paid quarterly over the next
twelve months, from EPNG and we recorded a gain of $882 thousand related to the
sale of Copper Eagle. In the event of EPNG default, the Copper Eagle Gas Storage
project will revert back to the original owners without compensation to EPNG.

In September 2003, we entered into a nonbinding letter of intent with
Southern Natural Gas Company, a subsidiary of El Paso Corporation, regarding the
proposed development and sale of a natural gas storage cavern and the proposed
sale of an undivided interest in a pipeline and other facilities related to that
natural gas storage cavern. The new storage cavern would be located at our
storage complex near Hattiesburg, Mississippi. If Southern Natural Gas
determines that there is sufficient market interest, it would purchase the land
and mineral rights related to the proposed storage cavern and would pay our
costs to construct the storage cavern and related facilities. Upon completion of
the storage cavern, Southern Natural Gas would acquire an undivided interest in
our Petal pipeline connected to the storage cavern. We would also enter into an
arrangement with Southern Natural Gas under which we would operate the storage
cavern and pipeline on its behalf.

Before we consummate this transaction, and enter into definitive
transaction documents, the transaction must be recommended by the audit and
conflicts committee of our general partner's board of directors, which committee
consists solely of directors meeting the independent director requirements
established by the NYSE and the Sarbanes-Oxley Act, and then approved by our
general partner's full board of directors.

In October 2003, we exchanged with El Paso Corporation its obligation to
repurchase the Chaco plant from us in 19 years for additional assets (refer to
Note 2). Also in October 2003, we redeemed all of our outstanding Series B
preference units (refer to Note 8).

The counterparty for one of our San Juan hedging activities is J. Aron and
Company, an affiliate of Goldman Sachs. Goldman Sachs was also a co-manager of
our 4,800,000 public common unit offering in October 2003, and is one of the
lenders under our revolving credit facility and owned 9.9 percent of our general
partner during part of the fourth quarter of 2003.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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

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$2 million payment in the first quarter of 2004. The present value of the
amounts due from El Paso Corporation were classified as follows:

11. COMMITMENTS AND CONTINGENCIES

Legal Proceedings

Grynberg. In 1997, we, along with numerous other energy companies, 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 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). Discovery is proceeding. Our costs and legal exposure related
to these lawsuits and claims are not currently determinable.

Will Price (formerly Quinque). We, along with numerous other energy
companies, are named defendants in Will Price, et al v. Gas Pipelines and Their
Predecessors, et al, filed in 1999 in the District Court of Stevens County,
Kansas. Plaintiffs allege that the defendants mismeasured natural gas volumes
and heating content of natural gas on non-federal and non-Native American lands,
and seek certification of a nationwide class of natural gas working interest
owners and natural gas royalty owners to recover royalties that they contend
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 of a nationwide class of
natural gas working interest owners and natural gas royalty owners was denied on
April 10, 2003. Plaintiffs were granted leave to file a Fourth Amended Petition,
which narrows the proposed class to royalty owners in wells in Kansas, Wyoming
and Colorado and removes claims as to heating content. A second class action
petition has been filed as to heating content claims. Our costs and legal
exposure related to these lawsuits and claims are not currently determinable.

In connection with our April 2002 acquisition of the EPN Holding assets,
subsidiaries of El Paso Corporation have agreed to indemnify us against all
obligations related 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 natural gas in areas of western Texas related to
an asset now owned by GulfTerra 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 filed an appeal with the
Eighth Court of Appeals in El Paso, Texas. On August 15, 2003 the

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Court of Appeals reversed the lower's courts calculation of past judgment
interest but otherwise affirmed the judgment. A motion for a rehearing was
denied. A petition for review by the Texas Supreme Court has been filed.

Also, GulfTerra Texas Pipeline L.P., (GulfTerra Texas, formerly known as
EPGT Texas Pipeline L.P.) now owned by GulfTerra Holding, was involved in
litigation with the City of Edinburg concerning the City's claim that GulfTerra
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 GulfTerra
Texas and is now owned by Southern Union Gas Company. An adverse judgment
against Southern Union and GulfTerra Texas was rendered in Hidalgo County State
District court in December 1998 and found a breach of contract, and held both
GulfTerra Texas and Southern Union jointly and severally liable to the City for
approximately $4.7 million. The judgment relied on the single business
enterprise doctrine to impose contractual obligations on GulfTerra Texas and
Southern Union entities that were not parties to the contract with the City.
GulfTerra Texas appealed this case to the Texas Supreme Court seeking reversal
of the judgment rendered against GulfTerra Texas. The City sought a remand to
the trial court of its claim of tortious interference against GulfTerra Texas.
Briefs were filed and oral arguments were held in November 2002. In October
2003, the Texas Supreme Court issued an opinion in favor of GulfTerra Texas and
Southern Union on all issues. The City has requested rehearing.

In December 2000, a 30-inch natural gas pipeline jointly owned by GulfTerra
Intrastate, L.P. (GulfTerra Intrastate) now owned by GulfTerra Holding, and
Houston Pipe Line Company LP ruptured in Mont Belvieu, Texas, near Baytown,
resulting in substantial property damage and minor physical injury. GulfTerra
Intrastate is the operator of the pipeline. Two lawsuits were filed in the state
district court in Chambers County, Texas by eight plaintiffs, including two
homeowners' insurers. The suits sought recovery for physical pain and suffering,
mental anguish, physical impairment, medical expenses, and property damage.
Houston Pipe Line Company was added as an additional defendant. In accordance
with the terms of the operating agreement, GulfTerra Intrastate agreed to assume
the defense of and to indemnify Houston Pipe Line Company. As of December 31,
2003, all claims have now been settled and these settlements had no impact on
our financial statements.

The City of Corpus Christi, Texas (the "City") alleged that GulfTerra Texas
and various Coastal entities owed it monies for past obligations under City
ordinances that propose to tax GulfTerra Texas on its gross receipts from local
natural gas sales for the use of street rights-of-way. Some but not all of the
GulfTerra Texas pipe at issue has been using the rights-of-way since the 1960's.
In addition, the City demanded that GulfTerra Texas agree to a going-forward
consent agreement in order for the GulfTerra Texas pipe and Coastal pipe to have
the right to remain in the City rights-of-way. In December 2003, GulfTerra Texas
and the City entered into a license agreement releasing GulfTerra Texas from any
past obligations and providing certain rights for the use of the City
rights-of-way and City owned property. This agreement was retroactive to October
1, 2002.

In August 2002, we acquired the Big Thicket assets, which consist of the
Vidor plant, the Silsbee compressor station and the Big Thicket gathering system
located in east Texas, for approximately $11 million from BP America Production
Company (BP). Pursuant to the purchase agreement, we have identified
environmental conditions that we are working with BP and appropriate regulatory
agencies to address. BP has agreed to indemnify us for exposure resulting from
activities related to the ownership or operation of these facilities prior to
our purchase (i) for a period of three years for non-environmental claims and
(ii) until one year following the completion of any environmental remediation
for environmental claims. Following expiration of these indemnity periods, we
are obligated to indemnify BP for environmental or non-environmental claims. We,
along with BP and various other defendants, have been named in the following two
lawsuits for claims based on activities occurring prior to our purchase of these
facilities.

Christopher Beverly and Gretchen Beverly, individually and on behalf of the
estate of John Beverly v. GulfTerra GC, L.P., et. al. In June 2003, the
plaintiffs sued us in state district court in Hardin County,
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Texas. The plaintiffs are the parents of John Christopher Beverly, a two year
old child who died on April 15, 2002, allegedly as the result of his exposure to
arsenic, benzene and other harmful chemicals in the water supply. Plaintiffs
allege that several defendants responsible for that contamination, including us
and BP. Our connection to the occurrences that are the basis for this suit
appears to be our August 2002 purchase of certain assets from BP, including a
facility in Hardin County, Texas known as the Silsbee compressor station. Under
the terms of the indemnity provisions in the Purchase and Sale Agreement between
GulfTerra and BP, GulfTerra requested that BP indemnify GulfTerra for any
exposure. BP has agreed to indemnify us in this matter.

Melissa Duvail, et. al., v. GulfTerra GC, L.P., et. al. In June 2003,
seventy-four residents of Hardin County, Texas, sued us and others in state
district court in Hardin County, Texas. The plaintiffs allege that they have
been exposed to hazardous chemicals, including arsenic and benzene, through
their water supply, and that the defendants are responsible for that exposure.
As with the Beverly case, our connection with the occurrences that are the basis
of this suit appears to be our August 2002 purchase of certain assets from BP,
including a facility known as the Silsbee compressor station, which is located
in Hardin County, Texas. Under the terms of the indemnity provisions in the
Purchase and Sale Agreement between us and BP, BP has agreed to indemnify us for
this matter.

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, 2003, 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 to have a material adverse effect on our financial
position, results of operations or cash flows. As new information becomes
available or relevant developments occur, we will establish accruals as
appropriate.

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, 2003, we had a reserve of approximately $21 million, included in other
noncurrent liabilities, 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. As part of the November 2002
San Juan assets acquisition, El Paso Corporation has agreed to indemnify us for
all the known and unknown environmental liabilities related to the assets we
purchased 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 of this
acquisition. In addition, we have been indemnified by third parties for
remediation costs associated with other assets we have purchased. We expect to
make capital expenditures for environmental matters of approximately $3 million
in the aggregate for the years 2004 through 2008, primarily to comply with clean
air regulations.

Shoup Air Permit Violation. On December 16, 2003, El Paso Field Services,
L.P. received a Notice of Enforcement (NoE) from the Texas Commission on
Environmental Quality (TCEQ) concerning alleged Clean Air Act violations at its
Shoup, Texas plant. The NoE included a draft Agreed Order assessing a penalty of
$365,750 for the cited violations. The alleged violations pertained to emission
limit exceedences, testing, reporting, and recordkeeping issues in 2001. While
the NoE was addressed to El Paso Field Services,

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L.P., the substance of the NoE also concerns equipment owned at the Shoup plant
by Gulfterra GC, L.P. El Paso Field Services, L.P. has responded to the NoE and
is preparing to meet with the TCEQ to discuss the alleged violations and the
proposed penalty.

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 to
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.
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 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 this information becomes available, or relevant
developments occur,we will adjust our accrual amounts accordingly. 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 Final Rule. In November 2003, the FERC issued a Final
Rule extending its 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 facility, including
the 60-mile Petal natural gas pipeline, are interstate facilities as defined by
the Natural Gas Act, the regulations dictate how HIOS and Petal conduct business
and interact with all energy affiliates of El Paso Corporation and us.

The standards of conduct require us, absent a waiver, to functionally
separate our HIOS and Petal interstate facilities from our other entities. We
must dedicate employees to manage and operate our interstate facilities
independently from our other Energy Affiliates. This employee group must
function independently and is prohibited from communicating non-public
transportation information or customer information to its Energy Affiliates.
Separate office facilities and systems are necessary because of the requirement
to restrict affiliate access to interstate transportation information. The Final
Rule also limits the sharing of employees and offices with Energy Affiliates.
The Final Rule was effective on February 9, 2004, subject to possible rehearing.
On that date, each transmission provider filed with FERC and posted on the
internet website a plan and scheduling for implementing this Final Rule. By June
1, 2004, written procedures implementing this Final Rule will be posted on the
internet website. Requests for rehearing have been filed and are pending. At
this time, we cannot predict the outcome of these requests, but at a minimum,
adoption of the regulations in the form outlined in the Final Rule will place
additional administrative and operational burdens on us.

Pipeline Safety Final Rule. In December 2003, the U.S. Department of
Transportation issued a Final Rule requiring pipeline operators to develop
integrity management programs for gas transmission pipelines located where a
leak or rupture could do the most harm in "high consequence areas," or HCA. The
final rule requires operators to (1) perform ongoing assessments of pipeline
integrity; (2) identify and characterize applicable threats to pipeline segments
that could impact an HCA; (3) improve data collection, integration and analysis;
(4) repair and remediate the pipeline as necessary; and (5) implement preventive
and mitigative actions. The final rule incorporates the requirements of the
Pipeline Safety Improvement Act of 2002, a new bill signed into law in December
2002. The Final Rule is effective as of January 14, 2004. At this time, we
cannot predict the outcome of this final rule.

Other Regulatory Matters. HIOS 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 FERC approved tariff that governs its operations,
terms and conditions of service, and rates. We timely filed a required rate case
for HIOS on December 31, 2002. The rate filing and tariff changes are based on
HIOS' cost of service,
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which includes operating costs, a management fee and changes to depreciation
rates and negative salvage amortization. We requested the rates be effective
February 1, 2003, but the FERC suspended the rate increase until July 1, 2003,
subject to refund. As of July 1, 2003, HIOS implemented the requested rates,
subject to a refund, and has established a reserve for its estimate of its
refund obligation. We will continue to review our expected refund obligation as
the rate case moves through the hearing process and may increase or decrease the
amounts reserved for refund obligation as our expectation changes. The FERC has
conducted a hearing on this matter and an initial decision is expected to be
issued in April 2004.

During the latter half of 2002, we experienced a significant unfavorable
variance between the fuel usage on HIOS and the fuel collected from our
customers for our use. We believe a series of events may have contributed to
this variance, including two major storms that hit the Gulf Coast Region (and
these assets) in late September and early October of 2002. As of December 31,
2003, we had recorded fuel differences of approximately $8.2 million, which is
included in other non-current assets. We are currently in discussions with the
FERC as well as our customers regarding the potential collection of some or all
of the fuel differences. At this time we are not able to determine what amount,
if any, may be collectible from our customers. Any amount we are unable to
resolve or collect from our customers will negatively impact our earnings.

In December 1999, GulfTerra 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 GulfTerra 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. GulfTerra Texas has established a reserve for refunds. In
July 2002, GulfTerra 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. On February 25, 2004, the FERC issued an order denying
GulfTerra Texas' request for rehearing and ordered GulfTerra Texas to file,
within 45 days from the issuance of the order, a calculation of refunds and a
refund plan. Additionally, the FERC ordered GulfTerra Texas to file a new rate
case or justification of existing rates within three years from the date of the
order.

In July 2002, Falcon Gas Storage, a competitor, also requested late
intervention and rehearing of the order. Falcon asserts that GulfTerra Texas'
imbalance penalties and terms of service preclude third parties from offering
imbalance management services. The FERC denied Falcon's late intervention on
February 25, 2004. Meanwhile in December 2002, GulfTerra Texas amended its
Statement of Operating Conditions to provide shippers the option of resolving
daily imbalances using a third-party imbalance service provider.

Falcon filed a formal complaint in March 2003 at the Railroad Commission of
Texas claiming that GulfTerra Texas' imbalance penalties and terms of service
preclude third parties from offering hourly imbalance management services on the
GulfTerra Texas system. GulfTerra Texas filed a response specifically denying
Falcon's assertions and requesting that the complaint be denied. The Railroad
Commission has set their case for hearing beginning on April 13, 2004. The City
Board of Public Service of San Antonio filed an intervention in opposition to
Falcon's complaint.

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 to have a material adverse effect on
our financial position, results of operations or cash flows. As new information
becomes available or relevant developments occur, we will establish accruals as
appropriate.

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Joint Ventures

We conduct a portion of our business through joint venture arrangements
(including our Cameron Highway, Deepwater Gateway and Poseidon joint ventures)
we form to construct, operate and finance the development of our onshore and
offshore midstream energy businesses. We are obligated to make our proportionate
share of additional capital contributions to our joint ventures only to the
extent that they are unable to satisfy their obligations from other sources
including proceeds from credit arrangements.

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. We also have long-term operating lease commitments associated
with two NGL storage facilities in Texas we acquired in November 2002 in
connection with our San Juan asset acquisition. The leases covering these
facilities expire in 2006 and 2012.

The future minimum lease payments under these operating lease commitments
as of December 31, 2003 are as follows (in millions):

2004........................................................ $ 7
2005........................................................ 7
2006........................................................ 7
2007........................................................ 6
2008........................................................ 3
Thereafter.................................................. 2
---
Total minimum lease payments................................ $32
===

Rental expense under operating leases was approximately $7.2 million and
$3.9 million for the years ended December 31, 2003 and 2002. We did not have any
operating leases prior to our acquisition of the EPN Holding assets in April
2002.

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.

12. ACCOUNTING FOR HEDGING ACTIVITIES

A majority of our commodity purchases and sales, which relate to sales of
oil and natural gas associated with our production operations, purchases and
sales of natural gas associated with pipeline operations, sales of natural gas
liquids and purchases or sales of gas associated with our processing plants and
our gathering activities, 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 Derivative Instruments 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 2003, 2002
and 2001, we entered into cash flow hedges.

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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 through current earnings since it did not
qualify for hedge accounting under SFAS No. 133. Through the acquisition date in
2002, 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. In February and August 2003, we entered into additional derivative
financial instruments to continue to hedge our exposure during 2004 to changes
in natural gas prices relating to gathering activities in the San Juan Basin.
The derivatives are financial swaps on 30,000 MMBtu per day whereby we receive
an average fixed price of $4.23 per MMBtu and pay a floating price based on the
San Juan index. As of December 31, 2003 and 2002, the fair value of these cash
flow hedges was a liability of $5.8 million and $4.8 million, as the market
price at those dates was higher than the hedge price. For the year ended
December 31, 2003, we reclassified approximately $9.8 million of unrealized
accumulated loss related to these derivatives from accumulated other
comprehensive income as a decrease in revenue. 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. 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.

In connection with our GulfTerra Alabama Intrastate 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 2002 and 2003 to offset the risk of increasing natural
gas prices. As of December 31, 2003, the fair value of these cash flow hedges
was an asset of approximately $77 thousand. For the twelve months ended December
31, 2003, we reclassified approximately $218 thousand of unrealized accumulated
gain related to these derivatives from accumulated other comprehensive income to
earnings. As of December 31, 2002, the fair value of these cash flow hedges was
an asset of $86 thousand. During the year ended December 31, 2002, we
reclassified a loss of $1.4 million 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 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.

During 2003, we entered into additional derivative financial instruments to
hedge a portion of our business' exposure to changes in NGL prices during 2003
and 2004. We entered into financial swaps for 3,500 barrels per day for February
through June 2003, 3,200 barrels per day for July 2003, 4,900 barrels per day
for August 2003, and 6,000 barrels per day for August 2003 through September
2004. The average fixed price received was $0.49 per gallon for 2003 and will be
$0.47 per gallon for 2004 while we pay a monthly average floating price based on
the OPIS average price for each month. As of December 31, 2003, the fair value
of these cash flow hedges was a liability of $3.3 million. For the twelve months
ended December 31, 2003, we reclassified approximately $0.4 million of
unrealized accumulated loss related to these derivatives from accumulated other
comprehensive income to earnings.

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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
$185 million variable rate revolving credit facility at 3.49% over the life of
the swap. Prior to April 2003, under its credit facility, Poseidon paid an
additional 1.50% over the LIBOR rate resulting in an effective interest rate of
4.99% on the hedged notional amount. Beginning in April 2003, the additional
interest Poseidon pays over LIBOR was reduced resulting in an effective fixed
interest rate of 4.74% on the hedged notional amount. This interest rate swap
expired on January 9, 2004. We have recognized as a reduction in income our 36
percent share of Poseidon's realized loss on the interest rate swap of $1.7
million for the twelve months ended December 31, 2003, or $0.6 million, through
our earnings from unconsolidated affiliates. As of December 31, 2002, the fair
value of its interest rate swap was a liability of $1.4 million, as the market
interest rate was lower than the hedge rate, 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. Additionally, we 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.

We estimate the entire $9.0 million of unrealized losses included in
accumulated other comprehensive income at December 31, 2003, will be
reclassified from accumulated other comprehensive income as a reduction to
earnings over the next 12 months. When our derivative financial instruments are
settled, the related amount in accumulated other comprehensive income is
recorded in the income statement in operating revenues, cost of natural gas and
other products, or interest and debt expense, depending on the item being
hedged. The effect of reclassifying these amounts to the income statement line
items is recording our earnings for the period at the "hedged price" under the
derivative financial instruments.

In July 2003, to achieve a better mix of fixed rate debt and variable rate
debt, we entered into an eight-year interest rate swap agreement to provide for
a floating interest rate on $250 million out of $480 million of our 8 1/2%
senior subordinated notes due 2011. With this swap agreement, we pay the
counterparty a LIBOR based interest rate plus a spread of 4.20% (which rate was
1.55% at December 31, 2003) and receive a fixed rate of 8 1/2%. We are
accounting for this derivative as a fair value hedge under SFAS No. 133. As of
December 31, 2003, the fair value of the interest rate swap was a liability
included in non-current liabilities of approximately $7.4 million and the fair
value of the hedged debt decreased by the same amount.

The counterparties for our San Juan hedging activities are J. Aron and
Company, an affiliate of Goldman Sachs, and UBS Warburg. We do not require
collateral and do not anticipate non-performance by these counterparties.
Through June 2003, the counterparty for our GulfTerra Alabama Intrastate
operations was El Paso Merchant Energy. Beginning in August 2003, the
counterparty is UBS Warburg, and we do not require collateral or anticipate
non-performance by this counterparty. The counterparty for our NGL hedging
activities for the Indian Basin and Chaco plants is J. Aron and Company, an
affiliate of Goldman Sachs. We do not require collateral and do not anticipate
non-performance by this counterparty. The counterparty for Poseidon's hedging
activity is Credit Lyonnais. Poseidon does not require collateral and does not
anticipate non-performance by this counterparty. Wachovia Bank is our
counterparty on our interest rate swap on the 8 1/2% notes, and we do not
require collateral or anticipate non-performance by this counterparty.

13. SUPPLEMENTAL DISCLOSURES TO THE STATEMENTS OF CASH FLOWS

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

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

14. MAJOR CUSTOMERS

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

The 2003 major customers are a result of our San Juan asset acquisition in
November 2002. Also, during 2003 we decreased our activities with affiliates of
El Paso Corporation, including replacing all our month-to-month arrangements
that were previously with El Paso Merchant Energy with similar arrangements with
third parties. 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 acquisition completed in 2002.

15. 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 and 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.

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GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

We use performance cash flows (which we formerly referred to as EBITDA) to
evaluate the performance of our segments, determine how resources will be
allocated and develop strategic plans. We define performance cash flows as
earnings before interest, income taxes, depreciation and amortization and other
adjustments. Historically our lenders and equity investors have viewed our
performance cash flows measure as an indication of our ability to generate
sufficient cash to meet debt obligations or to pay distributions, we believe
that there has been a shift in investors' evaluation regarding investments in
MLPs and they now put as much focus on the performance of an MLP investment as
they do its ability to pay distributions. For that reason, we disclose
performance cash flows as a measure of our segment's performance. We believe
performance cash flows is also useful to our investors because it allows them to
evaluate the effectiveness of our business segments from an operational
perspective, exclusive of the costs to finance those activities, income taxes
and depreciation and amortization, none 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.

141

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 and GTM Texas in February 2001. The
acquisitions were accounted for as 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) 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 record an intersegment
revenue elimination, which is the only elimination included in the
"Non-Segment Activity" column, to remove intersegment transactions.

(2) The revenue amount for our Oil and NGL Logistics segment has been reduced by
$10.5 million to reflect the reclassification of Typhoon Oil Pipeline's cost
of sales and other products. See Note 1, Summary of Significant Accounting
Policies, for a further discussion.

142

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

A reconciliation of our segment performance cash flows to our net income is
as follows:

16. 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, 2003, our credit facility is guaranteed by each
of our subsidiaries, excluding our unrestricted subsidiaries (Arizona Gas
Storage, L.L.C. and GulfTerra Arizona Gas, L.L.C.), and is collateralized by
substantially all of our assets. In addition, all of our senior notes and senior
subordinated notes are jointly, severally, fully and unconditionally guaranteed
by us and all our subsidiaries, excluding our unrestricted subsidiaries. As of
December 31, 2002, our revolving credit facility, GulfTerra 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
(Matagorda Island Area Gathering System, Arizona Gas Storage, L.L.C. and
GulfTerra Arizona Gas, L.L.C.), 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, severally,
fully and unconditionally guaranteed by us and all our subsidiaries excluding
our unrestricted subsidiaries. The consolidating eliminations column on our
condensed consolidating balance sheets below eliminates our investment in
consolidated subsidiaries, intercompany payables and receivables and other
transactions between subsidiaries. The consolidating eliminations column in our
condensed consolidating statements of income and cash flows eliminates earnings
from our consolidated affiliates.

143

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Non-guarantor subsidiaries for the year ended December 31, 2003, consisted
of our unrestricted subsidiaries (Arizona Gas Storage, L.L.C. and GulfTerra
Arizona Gas, L.L.C.). Non-guarantor subsidiaries for the year ended December 31,
2002, consisted of Argo and Argo I for the quarter ended March 31, 2002, our
GulfTerra Holding (then known as EPN Holding) subsidiaries, which owned the EPN
Holding assets and equity interests in GulfTerra Holding (then known as EPN
Holding), 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.

144

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 2003

145

GULFTERRA 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.

146

GULFTERRA 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.

147

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING BALANCE SHEETS
DECEMBER 31, 2003

148

GULFTERRA 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.

149

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
YEAR ENDED DECEMBER 31, 2003

150

GULFTERRA 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.
151

GULFTERRA 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.

152

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

General

This footnote discusses our oil and natural gas production activities for
the year 2001. The years 2003 and 2002 are 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. Estimates of our
reserves at December 31, 2001 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.

153

GULFTERRA 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

154

GULFTERRA 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
platform services 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. On a consolidated basis, our
standardized measure of discounted future net cash flows was $43,789 for
2001.

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:

155

GULFTERRA 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 year ended
December 31:

In the year presented, we elected not to incur any costs to develop our
proved undeveloped 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:

Results of operations

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

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

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

156

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

18. SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION:

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

(1) Since November 2002, when we acquired the Typhoon Oil Pipeline, we have
recognized revenue attributable to it using the "gross" method, which means
we record as "revenues" all oil that we purchase from our customers at an
index price less an amount that compensates us for our service and we record
as "cost of oil" that same oil which we resell to those customers at the
index price. We believe that a "net" presentation is more appropriate than a
"gross" presentation and is consistent with how we evaluate the performance
of the Typhoon Oil Pipeline. Based on our review of the accounting
literature, we believe that generally accepted accounting principles permit
us to use the "net" method, and accordingly we have presented the results of
Typhoon Oil "net" for all periods. To reflect this reclassification,
operating revenues have been reduced by $48.8 million, $73.1 million and
$69.8 million for the quarters ended March 31, June 30 and September 30 of
2003. This change does not affect operating income or net income.

(2) As a result of the loss allocated to our common unitholders during the
quarter ended December 31, 2003, the basic and diluted earnings per common
units are the same.

157

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

(1) Operating revenues for the quarter ended December 31, 2002, have been
reduced by $10.5 million to reflect the reclassification of Typhoon Oil
Pipeline's cost of oil.

158

REPORT OF INDEPENDENT AUDITORS

To the Unitholders of GulfTerra Energy Partners, L.P.
and the Board of Directors and Stockholders of
GulfTerra Energy Company, L.L.C., as General Partner:

In our opinion, the consolidated financial statements listed in the index
appearing under Item 15(a)1. on page 172 present fairly, in all material
respects, the financial position of GulfTerra Energy Partners, L.P. and its
subsidiaries (the "Partnership") at December 31, 2003 and 2002, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2003 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 2 to the consolidated financial statements, the
Partnership has entered into a definitive agreement to merge with Enterprise
Products Partners L.P.

As discussed in Note 1 to the consolidated financial statements, the
Partnership changed its method of accounting for asset retirement obligations
and its reporting for gains or losses resulting from the extinguishment of debt
effective January 1, 2003.

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

/s/ PricewaterhouseCoopers LLP

Houston, Texas
March 12, 2004

159

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

None.

ITEM 9A. 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 over financial reporting (Internal Controls) as of the end
of the period covered by 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. The design of a control system must reflect the fact that there are
resource constraints, and the benefits of controls must be 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. Therefore, 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. Our
Disclosure Controls and Internal Controls are designed to provide such
reasonable assurances of achieving our desired control objectives, and our
principal executive officer and principal financial officer have concluded that
our Disclosure Controls and Internal Controls are effective in achieving that
level of reasonable assurance.

No Significant Changes in Internal Controls. We have sought to determine
whether there were any "significant deficiencies" or "material weaknesses" in
our Internal Controls, or whether we had identified any acts of fraud involving
personnel who have a significant role in our 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 the Audit and Conflicts Committee of our general
partner's board of directors 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 there have not been any
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 the Disclosure Controls are effective to ensure that material information
relating to us and our consolidated subsidiaries is made known to our
management, including the principal executive officer and principal financial
officer, on timely basis.

160

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 as Exhibits to this Annual
Report.

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 10, 2004, no officer or director has established a trading plan. However,
we will 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 the NYSE listing standards, 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, unitholder 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, W. Matt
Ralls and Kenneth L. Smalley are "independent" directors under the NYSE rules.
Thus, the Board of Directors of our general partner has a majority (67 percent)
of independent directors.

Heightened Independence for Audit and Conflicts Committee Members. As
required by the Sarbanes-Oxley Act of 2002 and SEC 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 its 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 rules require that public companies disclose whether or not its
audit committee has an "audit committee financial expert" as a

161

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
GulfTerra 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
holds 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, one director is designated as the
"Presiding Director," who is responsible for leading and facilitating such
executive sessions. For 2003, the Presiding Director was Michael B. Bracy, the
Chairman of the Audit and Conflicts Committee. For 2004, the Presiding Director
is Kenneth L. Smalley, the Chairman of the Governance and Compensation
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. The Board of Directors of our general
partner has two committees: the Audit and Conflicts Committee and the Governance
and Compensation Committee.

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 GulfTerra 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 GulfTerra Energy Partners Governance
Guidelines annually or more often as deemed necessary.

Code of Ethics. We have adopted a code of ethics, the "Code of Business
Conduct," that applies to all of our directors and employees, including its
Chief Executive Officer, Chief Financial Officer and senior financial and
accounting officers. In addition to other matters, the Code of Business Conduct
establishes policies to deter wrongdoing and to promote honest and ethical
conduct, including ethical handling of actual or apparent conflicts of interest,
compliance with applicable laws, rules and regulations, full, fair, accurate,
timely and understandable disclosure in public communications and prompt
internal reporting violations of the code. A copy of our Code of Business
Conduct is available on our website at www.gulfterra.com. We intend to post any
waivers to or amendments of our Code of Business Conduct which are required by
applicable law to be disclosed on our website at www.gulfterra.com.

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 GulfTerra Energy Partners Governance Guidelines
and other matters impacting our governance principles. We also provide access
through our website to all filings submitted by GulfTerra Energy Partners with
the SEC. The company's website is www.gulfterra.com and access to this
information is free of any charge to the user.

162

DIRECTORS AND EXECUTIVE OFFICERS OF OUR GENERAL PARTNER

The following table sets forth certain information as of March 10, 2004,
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 managing member, GulfTerra GP Holding Company, 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.

On January 28, 2003, the Board of Directors of our general partner
established a Governance and Compensation Committee, determined that all three
members of the audit and conflicts committee (Messrs. Bracy, Church and
Smalley), satisfy the independence requirements for audit committee eligibility
and determined that Mr. Bracy is an audit committee financial expert as
determined by the SEC 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. Manias assumed the position of Chief Financial Officer in February
2004. Mr. Manias was most recently Vice President, Business Development and
Strategic Planning for El Paso Field Services Company, a subsidiary of El Paso
Corporation. Prior to that position, he served as Vice President of Global Power
and Pipeline Investment Banking for J.P. Morgan Securities.

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 GulfTerra Energy Partners, L.P.

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

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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.

Mr. Ralls has served as a Director of our general partner since May 2003.
Mr. Ralls is Senior Vice President and Chief Financial Officer of GlobalSantaFe,
one of the largest international drilling contractors, providing offshore and
land drilling services to the world's leading oil and gas companies. From 1997
to 2001, he was Global Marine's Vice President, Chief Financial Officer and
Treasurer. Previously, he served as executive Vice President, Chief Financial
Officer and a Director of Kelley Oil and Gas Corporation and as Vice President
of Capital Markets and Corporate Development for The Meridian Resource
Corporation before joining Global Marine.

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 $40,000, with the chairman of any board committees
entitled to receive an additional $15,000 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.

In August 1998, we adopted our Common Unit Plan for Non-Employee Directors,
or our 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; an annual unit option grant of 2,000 unit
options; and 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 the applicable 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 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 8,500 unit options to purchase an equal
number of common units with an exercise price of $32.71 per unit and 4,090
restricted units; in 2002, we granted 8,000 unit options to purchase an equal
number of common units with an exercise price of $32.23 per unit and 5,429
restricted units; and in 2003, we granted 10,500 unit options to purchase an
equal number of common units with an exercise price of $35.92 per unit and 5,226
restricted units. At February 9, 2004, 47,755 units remain unissued under the
Director Plan.

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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
has been determined by the Board of Directors of our general partner to be
"independent" (as such term is defined in the NYSE listing standards) and
financially literate. With respect to the 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 our policies and
practices, as well as those of our general partner. 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. Our
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.A.

GOVERNANCE AND COMPENSATION COMMITTEE

The Governance and Compensation Committee was formed on January 28, 2003.
The Governance and Compensation Committee currently consists of Messrs. Smalley
(chairman), Bracy and Church, each a non-employee director, and each of whom has
been determined by the Board of Directors of our general partner to be
"independent" (as such term is defined in the NYSE listing standards). 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 reviews annually
and approves the individual elements of total compensation for our Chief
Executive Officer and other executive officers and prepares a report on the
factors and criteria on which their compensation was based.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

During 2003, 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 2003 was handled by El
Paso Corporation, the Governance and Compensation Committee is responsible for
establishing performance measures and making recommendations to El Paso
Corporation concerning compensation of its employees performing duties for us in
the future. 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.
165

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 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, we believe directors, executive officers and greater than 10 percent
beneficial owners complied with all filing requirements during the year ended
December 31, 2003.

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 our Omnibus Compensation Plan, or the Omnibus
Plan, to provide our general partner with the ability to issue unit options,
restricted units and other equity-based awards 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 $35.03 per unit pursuant to the Omnibus Plan. No grants of unit options
were made in 1999, 2000 or 2002. At February 9, 2004, 1,228,500 unit options
remain unissued under the Omnibus Plan.

REPORT FROM COMPENSATION COMMITTEE REGARDING EXECUTIVE COMPENSATION

As indicated above, the Governance and Compensation Committee was formed in
January 2003 and consists of Messrs. Smalley (chairman), Bracy and Church, each
an independent, non-employee director.

In our capacity as the Compensation Committee, we are responsible to review
the executive compensation program of the Partnership to ensure that it is
adequate to attract, motivate and retain competent executive personnel and that
it is directly and materially related to the short-term and long-term objectives
and operating performance of the Partnership. We periodically review and approve
the Partnership's stated compensation strategy to ensure that management is
rewarded appropriately for its contributions to Partnership growth and
profitability and that the executive compensation strategy supports organization
objectives.

Our responsibilities, as delegated by the Board of Directors, include the
following:

- We are to ensure the executive compensation program of the Partnership is
directly related to the Partnership's financial performance, and the
performance of the individual executive officer;

- Administer the equity compensation under the Omnibus Plan for executive
personnel;

- We shall review appropriate criteria for establishing performance targets
and determining annual organization and executive performance ratings;

166

- We shall determine appropriate levels of executive compensation by
periodically conducting a thorough competitive evaluation, reviewing
proprietary and proxy information, and consulting with and receiving
advice from an independent executive compensation consulting firm. We
have the ultimate authority and responsibility to select, evaluate and,
where appropriate, replace such independent executive compensation
consulting firm, including the sole authority to approve the firm's fees
and other retention terms;

- We shall ensure that the Partnership's executive compensation plans are
administered in accordance with stated compensation objectives, and shall
make recommendations to the Board of Directors with respect to such
plans;

- We shall review the Partnership's employee benefit and compensation
programs and approve management recommendations subject, where
appropriate, to Board of Director approval;

- We shall consider proposals with respect to the creation of and changes
to the Partnership's executive compensation program; and

- The Committee shall periodically review and make recommendations to the
full Board regarding annual retainer and meeting fees for the Board of
Directors and committees of the Board and shall propose the terms and
awards of equity compensation for members of the Board.

During 2003, we have met and discussed the specific elements of the
executive compensation program, as required above. However, because of our
current relationship with El Paso Corporation and our general partner, the
compensation committee of El Paso Corporation reviews and approves (as
appropriate) our recommendations with respect to the individual elements of
total compensation for our Chief Executive Officer and other executive officers
of the Partnership.

THE 2003 COMPENSATION COMMITTEE OF THE BOARD OF DIRECTORS

Kenneth L. Smalley Michael B. Bracy H. Douglas Church
(Chairman) (Member) (Member)

SUMMARY COMPENSATION TABLE

The following table sets forth information concerning the annual
compensation earned by our Chief Executive Officer and each of our other
executive officers:

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

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

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UNIT OPTION GRANTS

No unit options were granted to the named executives during 2003.

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 2003
AND FISCAL YEAR-END UNIT OPTION VALUES

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

(1)The figures presented in these columns have been calculated based upon the
difference between $42.655, the fair market value of the common units on
December 31, 2003, 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, 2003.

168

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth, as of February 29, 2004, 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, (iii) each required executive officer
and (iv) 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 1, 2004, 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 10,310,045 common units, or 17.6 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) 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.

CHANGES IN CONTROL

We have entered into a merger agreement with Enterprise under which, if the
merger closes, we will undergo a change of control. The proposed merger is
described in more detail previously in this document.

EQUITY COMPENSATION PLAN INFORMATION
AS OF DECEMBER 31, 2003

- ---------------
(1) Included in the equity compensation plans not approved by common unitholders
are the Omnibus Plan and Director Plan. These plans are described in Item 8,
Financial Statements and Supplementary Data, Note 8.

169

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 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
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 10. Also see Item 10, Directors
and Executive Officers of the Registrant.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following sets forth aggregate fees for professional services rendered
for us by PricewaterhouseCoopers LLP for the years ended December 31, 2003 and
2002, (in thousands):

The Audit fees represent fees for professional services rendered for the
audits of our annual consolidated financial statements, reviews of the related
quarterly consolidated financial statements, statutory subsidiary and equity
investee audits, the review of documents filed with the Securities and Exchange
Commission, consents, and the issuance of comfort letters.

The Audit-Related fees represent fees for internal control assessment and
accounting consultations.

Tax fees represent fees for services related to tax compliance, and tax
planning and advice, including services related to the preparation of unitholder
annual K-1 statements.

All Other fees represent fees for services other than services reported
above. No such services were rendered by PricewaterhouseCoopers LLP during the
last two years.

170

The Audit and Conflicts Committee of our general partner has adopted a
pre-approval policy for audit and non-audit services.

The Audit and Conflicts Committee has considered whether the provision of
non-audit services by PricewaterhouseCoopers LLP is compatible with maintaining
auditor independence and has determined that auditor independence has not been
compromised.

171

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.......
173

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.......................................... 174

172

SCHEDULE II

GULFTERRA ENERGY PARTNERS, L.P.

VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
(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.

173

GULFTERRA ENERGY PARTNERS, L.P.

EXHIBIT LIST
DECEMBER 31, 2003

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.

174

175

(b) REPORTS ON FORM 8-K

We filed a current report on Form 8-K dated October 10, 2003 to file (a)
the amendment to our partnership agreement, (b) our amended credit agreement,
(c) material agreements relating to Goldman Sachs' investment in us and our
general partner and (d) a consent from independent petroleum engineers.

We filed a current report on Form 8-K dated December 12, 2003 to file
amendments to our credit agreement and announce the redemption of certain of our
senior subordinated notes.

We filed a current report on Form 8-K dated December 15, 2003 to report our
proposed merger with Enterprise.

We filed a current report on Form 8-K dated February 3, 2004 to announce an
overview of our merger with Enterprise.

We filed a current report on Form 8-K dated February 11, 2004 to announce
William G. Manias has assumed the position of Chief Financial Officer.

We also furnished to the SEC current reports on Form 8-K under Item 9 and
Item 12. Current Reports on Form 8-K under Item 9 and Item 12 are not considered
to be "filed" for purposes of Section 18 of the Securities and Exchange Act of
1934 and are not subject to the liabilities of that section.

176

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, as amended, GulfTerra Energy Partners, L.P. has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized on the twelfth day of March 2004.

GULFTERRA ENERGY PARTNERS, L.P.

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
GulfTerra Energy Partners, L.P. and in the capacities and on the dates
indicated:

177

GULFTERRA ENERGY PARTNERS, L.P.

INDEX TO EXHIBITS
DECEMBER 31, 2003

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.