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

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

Furthermore, the rates we charge for our services are dependent on whether
the relevant pipeline system is regulated or unregulated, the quality of the
service required by the customer, and the amount and term of the reserve
commitment by the customer. Gathering arrangements are fee-based and, except for
the GulfTerra Alabama Intrastate and San Juan gathering system fees, generally
do not have exposure to risks

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

Regulatory Environment

Our natural gas pipeline systems are subject to the Natural Gas Pipeline
Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002, which
establishes pipeline and liquified natural gas plant safety requirements. All of
our offshore pipeline systems are subject to regulation under the Outer
Continental Shelf Lands Act, which calls for nondiscriminatory transportation on
pipelines operating in the outer continental shelf region of the Gulf of Mexico.
Each of the pipeline systems has continuous inspection and compliance programs
designed to keep our facilities in compliance with pipeline safety and pollution
control requirements. We believe that our pipeline systems are in material
compliance with the applicable requirements of these regulations.

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

Our HIOS system is also subject to the jurisdiction of the Federal Energy
Regulatory Commission (FERC) in accordance with the Natural Gas Act of 1938 and
the Natural Gas Policy Act of 1978. HIOS operates under a separate FERC approved
tariff that governs its operations, terms and conditions of service and rates.
The natural gas pipeline industry has historically been heavily regulated by
federal and state governments, and we cannot predict what further actions FERC,
state regulators, or federal and state legislators may take in the future. We
timely filed a required rate case for our HIOS system on December 31, 2002. The
rate filing and tariff changes are based on HIOS' cost of service, which
includes operating costs, a management fee, and changes to depreciation rates
and negative salvage amortization. HIOS' filing reflects a zero rate base;
therefore, a management fee in place of a return on rate base has been
requested. We requested the rates be effective February 1, 2003, but the FERC
suspended the rate increase until July 1, 2003, subject to refund. 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

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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.

The FERC has issued the final rule regarding marketing affiliates which
will affect our HIOS operations. See Part II, Item 8, Financial Statements and
Supplementary Data, Note 11 -- Commitments and Contingencies -- Rates and
Regulatory Matters.

GulfTerra Texas' FERC Section 311 service rates are subject to FERC rate
jurisdiction. 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 services. 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. In February 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 Company, Inc., 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 in February 2004. Falcon Gas Storage and its affiliate Hill-Lake
Gas Storage, L.P. 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 has filed an
intervention in opposition to Falcon's complaint.

Environmental

Our natural gas pipelines and plants are subject to various safety and
environmental statutes, including: the Natural Gas Act, the Natural Gas Policy
Act, the Outer Continental Shelf Act, the Hazardous Materials Transportation
Act, the Hazardous Liquid Pipeline Safety Act, the Resource Conservation and
Recovery Act, the Comprehensive Environmental Response, Compensation and
Liability Act, the Clean Air Act, the Federal Water Pollution Control Act, the
Endangered Species Act, the Occupational Safety and Health Act, the Emergency
Planning and Community Right-to-Know Act and similar state statutes. We have
ongoing programs designed to keep our natural gas pipelines and plants in
compliance with environmental and safety requirements, and we believe that our
facilities are in material compliance with the applicable requirements. As of
December 31, 2003, we had a reserve of approximately $21 million, included in
other noncurrent liabilities, for environmental 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. 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. For a discussion of environmental regulations, see
Environmental-Specific Regulations.

Maintenance

Each of our pipeline systems requires regular maintenance. The interior of
the pipelines is maintained through the regular cleaning of the line of liquids
that collect in the pipeline. Corrosion inhibitors are also injected into all of
the systems, except for our Viosca Knoll system and our Typhoon natural gas
pipeline, through the flow stream on a continuous basis. To maintain our
pipeline integrity on our Viosca Knoll system and our Typhoon natural gas
pipeline, we use water sample analysis, electron microscope analysis and a rigid
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pigging schedule. To prevent external corrosion of the pipe, anodes are fastened
to the pipeline itself at prescribed intervals, providing protection from the
effects of a corrosive environment, such as sea water. Our HIOS and Viosca Knoll
natural gas pipeline systems include platforms that are manned on a continuous
basis. The personnel on board these platforms are responsible for site
maintenance, operations of the platform facilities, measurement of the oil or
natural gas stream at the source of production and corrosion control.
Furthermore, the integrity of our onshore pipelines is subject to on-going
integrity assessment and evaluation pursuant to the Pipeline Integrity
Management Plan filed with the Railroad Commission of Texas and revised from
time to time. The Pipeline Integrity Management Plan identifies all pipelines
covered by the plan, establishes a priority ranking for performing the integrity
assessment of pipeline segments of each pipeline system and makes an assessment
of pipeline integrity using methods such as in-line inspection, pressure
testing, direct assessment or other technology or assessment methodology. This
integrity management program is reassessed and refined as necessary on at least
an annual basis by qualified personnel.

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

OIL AND NGL LOGISTICS

Offshore Oil Pipeline Systems

We own interests in three offshore oil pipeline systems, which extend over
340 miles and have a combined capacity of approximately 635 MBbls/d of oil with
the addition of pumps and the use of friction reducers. In addition to being
strategically located in the vicinity of some prolific oil-producing regions in
the Gulf of Mexico, our oil pipeline systems are parallel to and interconnect
with key segments of some of our natural gas pipeline systems and offshore
platforms, which contain separation and handling facilities. This distinguishes
us from our competitors by allowing us to provide some producing properties with
a unique single point of contact through which they may access a wide range of
midstream services and assets.

The following table and discussions describe our offshore oil pipelines.

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

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

9

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
10

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
11

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.

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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.

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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.

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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.

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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.

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PART II

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

Our common units are traded on the New York Stock Exchange (NYSE) under the
symbol "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.

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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

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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.

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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 subordi