EL PASO CGP CO - 10-K Annual Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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FORM 10-K

(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

OR

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

FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NUMBER 1-7176

EL PASO CGP COMPANY
(Exact Name of Registrant as Specified in Its Charter)

DELAWARE 74-1734212
(State or Other Jurisdiction (I.R.S. Employer
of Incorporation or Organization) Identification No.)

EL PASO BUILDING
1001 LOUISIANA STREET
HOUSTON, TEXAS 77002
(Address of Principal Executive Offices) (Zip Code)

TELEPHONE NUMBER: (713) 420-2600

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [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 Rule 12b-2 of the Act). Yes [ ] No [X]
STATE THE AGGREGATE MARKET VALUE OF THE VOTING AND NON-VOTING COMMON EQUITY
HELD BY NON-AFFILIATES OF THE REGISTRANT: NONE

INDICATE THE NUMBER OF SHARES OUTSTANDING AT EACH OF THE REGISTRANT'S
CLASSES OF COMMON STOCK, AS OF THE LATEST PRACTICABLE DATE.
Common Stock, par value $1 per share. Shares outstanding on March 26, 2003:
1,000

EL PASO CGP COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTION I(1)(a) AND
(b) TO FORM 10-K AND IS, THEREFORE, FILING THIS REPORT WITH A REDUCED DISCLOSURE
FORMAT AS PERMITTED BY SUCH INSTRUCTION.

DOCUMENTS INCORPORATED BY REFERENCE: NONE

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EL PASO CGP COMPANY

TABLE OF CONTENTS

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* We have not included a response to this item in this document since no
response is required pursuant to the reduced disclosure format permitted by
General Instruction I to Form 10-K.

Below is a list of terms that are common to our industry and used
throughout this document:

/d = per day
Bbl = barrels
BBtu = billion British thermal units
BBtue = billion British thermal unit
equivalents
Bcf = billion cubic feet
Bcfe = billion cubic feet of gas equivalents
MBbls = thousand barrels
Mcf = thousand cubic feet
Mcfe = thousand cubic feet of gas equivalents
Mgal = thousand gallons
MMBbls = million barrels
MMBtu = million British thermal units
MMcf = million cubic feet
MMcfe = million cubic feet of gas equivalents
MTons = thousand tons
MWh = megawatt hours
Tcfe = trillion cubic feet of gas equivalents

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 a pressure of 14.73 pounds per square inch.

When we refer to "us", "we", "our", "ours", or "Coastal", we are describing
El Paso CGP Company and/or our subsidiaries.

i

PART I

ITEM 1. BUSINESS

GENERAL

We are a Delaware corporation originally founded in 1955. In January 2001,
we became a wholly owned subsidiary of El Paso Corporation (El Paso) through our
merger with a wholly owned El Paso subsidiary. On January 30, 2001, we changed
our name from The Coastal Corporation to El Paso CGP Company.

Our principal operations include:

- natural gas transportation, gathering, processing and storage;

- natural gas and oil exploration, development and production;

- power generation;

- energy infrastructure facility development and operation;

- petroleum refining; and

- chemicals production.

SEGMENTS

Our operations are segregated into four primary business segments:
Pipelines, Production, Field Services and Merchant Energy. These segments are
strategic business units that provide a variety of energy products and services.
We manage each segment separately, and each segment requires different
technology and marketing strategies. As future developments in our business
occur and as we carry out our ongoing strategy and plans, we will continue to
assess the appropriateness of our business segments. For the operating results
and identifiable assets by segment, you should see Part II, Item 8, Financial
Statements and Supplementary Data, Note 18, which is incorporated herein by
reference.

Our Pipelines segment owns or has interests in approximately 19,600 miles
of interstate natural gas pipelines in the U.S. and internationally. In the
U.S., our systems connect the nation's principal natural gas supply regions to
the four largest consuming regions in the U.S.: the Gulf Coast, California, the
Northeast and the Midwest. Our U.S. pipeline systems also own or have interests
in over 280 Bcf of storage capacity used to provide a variety of services to our
customers. Our international pipeline operations include access between our U.S.
based systems and Canada.

Our Production segment conducts our natural gas and oil exploration and
production activities. Domestically, we lease approximately 1 million net acres
in 10 states, including Texas, Utah, and in the Gulf of Mexico. We also have
exploration and production rights in Australia, Bolivia, Brazil, Canada, Hungary
and Indonesia. During 2002, daily equivalent natural gas production exceeded 0.8
Bcfe/d, and our reserves at December 31, 2002, were approximately 2.3 Tcfe.

Our Field Services segment conducts our midstream activities. These
services include gathering natural gas from approximately 2,900 natural gas
wells with approximately 3,800 miles of natural gas gathering and natural gas
liquids (NGL) pipelines, and 12 natural gas processing, treating and
fractionation facilities located in producing regions of the south Texas, south
Louisiana, Mid-Continent and Rocky Mountain regions.

Our Merchant Energy segment consists of two primary divisions: global power
and petroleum. We are an owner of electric generating capacity and own or have
interests in 19 power plants in 8 countries. We operate three refineries that
have the capacity to process approximately 438 MBbls of crude oil per day and
produce a variety of petroleum products. We also produce agricultural and
industrial chemicals at four facilities in the U.S. On February 5, 2003, El Paso
announced its intent to sell our remaining petroleum and chemical assets, except
for our Aruba refinery. During 2002 and the first part of 2003, El Paso also
completed or announced several asset sales including the sale of our coal mining
assets and operations, petroleum assets and interests in power projects.

1

PIPELINES SEGMENT

Our Pipelines segment provides natural gas transmission, storage, gathering
and related services in the U.S. and internationally. We conduct our activities
primarily through three wholly owned and two partially owned interstate
transmission systems along with five underground natural gas storage entities.
The tables below detail our wholly owned and partially owned interstate
transmission systems:

Wholly Owned Interstate Transmission Systems

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(1) Includes throughput transported on behalf of affiliates.

Partially Owned Interstate Transmission Systems

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(1) Volumes represent the systems' total design capacity and average throughput
and are not adjusted for our ownership interest.

(2) The Alliance pipeline project commenced operations in the fourth quarter of
2000. We sold 12.3 percent of our equity interest in the system during the
fourth quarter of 2002, and the remaining 2.1 percent equity interest in the
first quarter of 2003.

In addition to the storage capacity on our transmission systems, we own or
have interests in the following natural gas storage entities:

Underground Natural Gas Storage Entities

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(1) Includes a total of 81 Bcf contracted to affiliates. Storage capacity is
under long-term contracts and is not adjusted for our ownership interest.

2

We have a number of transmission system expansion projects that have been
approved by the Federal Energy Regulatory Commission (FERC) as follows:

Our transportation, storage and related services (transportation services)
revenues consist of reservation and usage revenues. In 2002, approximately 92
percent of our transportation services revenues were attributable to a capacity
reservation or a demand charge paid by firm customers. These firm customers are
obligated to pay a monthly demand charge, regardless of the amount of natural
gas they transport or store, for the term of their contracts. The remaining 8
percent of our transportation services revenue was attributable to usage charges
based largely on the volumes of gas actually transported or stored on our
pipeline systems.

Regulatory Environment

Our interstate natural gas transmission systems and storage operations are
regulated by the FERC under the Natural Gas Act of 1938 and the Natural Gas
Policy Act of 1978. Each of our pipeline systems and storage facilities operates
under FERC-approved tariffs that establish rates, terms and conditions for
services to our customers. Generally, the FERC's authority extends to:

- rates and charges for natural gas transportation, storage, terminalling
and related services;

- certification and construction of new facilities;

- extension or abandonment of facilities;

- maintenance of accounts and records;

- relationships between pipeline and marketing affiliates;

- terms and conditions of service;

- depreciation and amortization policies;

- acquisition and disposition of facilities; and

- initiation and discontinuation of services.

The fees or rates established under our tariffs are a function of our costs
of providing services to our customers, including a return on our invested
capital. Consequently, our financial results have historically been relatively
stable; however, these results can be subject to volatility due to factors such
as weather, changes in natural gas prices and market conditions, regulatory
actions, competition and the creditworthiness of our customers.

In Canada, our pipeline activities are regulated by the National Energy
Board. Similar to the FERC, the National Energy Board governs tariffs and rates,
and the construction and operation of natural gas pipelines in Canada.

Our interstate pipeline systems are also subject to federal, state and
local pipeline safety and environmental statutes and regulations. Our systems
have ongoing programs designed to keep our facilities in compliance with
pipeline safety and environmental requirements. We believe that our systems are
in material compliance with the applicable requirements.

A discussion of significant rate and regulatory matters is included in Part
II, Item 8, Financial Statements and Supplementary Data, Note 16, and is
incorporated herein by reference.

3

Markets and Competition

The following table details our markets and competition on each of our
wholly owned pipeline systems as of December 31, 2002:

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(1) Includes natural gas producers, marketers, end-users and other natural gas
transmission, distribution and electric generation companies.

(2)The Cheyenne Plains project is a new 30-inch diameter pipeline proposed by us
to transport natural gas from the Cheyenne hub to the confluence of several
pipelines near Greensburg, Kansas. This pipeline is anticipated to be in
service in mid-2005 depending on the timing of regulatory approval.

Electric power generation is one of the fastest growing demand sectors of
the natural gas market. The potential consequences of proposed and ongoing
restructuring and deregulation of the electric power industry are currently
unclear. Restructuring and deregulation benefit the natural gas industry by
creating more

4

demand for natural gas turbine generated electric power, but this effect is
offset, in varying degrees, by increased generation efficiency and more
effective use of surplus electric capacity as a result of open market access. In
addition, in several regions of the country, new capacity additions have
exceeded load growth and transmission capabilities out of those regions. This
will result in lower growth in the gas demand in such regions associated with
new power generation facilities.

As our pipeline contracts expire, our ability to extend our existing
contracts or re-market expiring capacity is dependent on competitive
alternatives, the regulatory environment at the federal, state and local levels
and market supply and demand factors at the relevant dates these contracts are
extended or expire. The duration of new or re-negotiated contracts will be
affected by current prices, competitive conditions and judgments concerning
future market trends and volatility. Subject to regulatory constraints, we
attempt to re-contract or re-market our capacity at the maximum rates allowed
under our tariffs, although we, at times, discount these rates to remain
competitive. The level of discount varies for each of our pipeline systems.

As a result of the rating agencies downgrading the credit rating of several
members of the energy sector, including energy trading companies, and placing
them on negative credit watch, the creditworthiness of some customers has
deteriorated. We have taken actions to mitigate our exposure by requesting these
companies provide us with letters of credit or prepayments as permitted by our
tariffs. Our tariffs permit us to request additional credit assurance from our
shippers equal to the cost of performing transportation services for various
periods as specified in each tariff. If these companies experience financial
difficulties or file for Chapter 11 bankruptcy protection and our contracts are
not assumed by other counterparties, or if the capacity is unavailable for
resale, it could have a material adverse effect on our financial position,
operating results or cash flows.

PRODUCTION SEGMENT

Our Production segment is engaged in the exploration for, and the
acquisition, development and production of natural gas, oil and natural gas
liquids, primarily in North America. Domestically, we have onshore and coal seam
operations and properties in 10 states and offshore operations and properties in
federal and state waters in the Gulf of Mexico. Internationally, we have
exploration and production rights in Australia, Bolivia, Brazil, Canada, Hungary
and Indonesia.

Strategically, Production emphasizes disciplined investment criteria and
manages its existing production portfolio to maximize volumes and minimize
costs. It employs geophysical technology and seismic data processing to identify
economic hydrocarbon reserves. Production's deep drilling capabilities and
hydraulic fracturing technology allow it to optimize production with high-rate
completions at competitive reserve replacement costs. Production maintains an
active drilling program that capitalizes on its land and seismic holdings. It
also acquires production properties subject to acceptable investment return
criteria.

Natural Gas and Oil Reserves

The table below details Production's proved reserves at December 31, 2002.
Information in this table is based on the reserve report dated January 1, 2003,
prepared internally by Production and reviewed by Huddleston & Co., Inc. This
information is consistent with estimates of reserves filed with other federal
agencies except for differences of less than five percent resulting from actual
production, acquisitions, property sales, necessary reserve revisions and
additions to reflect actual experience. These reserves include 465,783 MMcfe of
production delivery commitments under financing arrangements that extend through
2042.

5

The financing arrangement supported by these reserves matures in 2006. Total
proved reserves on the fields with this dedicated production were 919,265 MMcfe.

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(1)Net proved reserves exclude royalties and interests owned by others and
reflects contractual arrangements and royalty obligations in effect at the
time of the estimate.
(2)Includes oil, condensate and natural gas liquids.
(3)Includes international operations in Brazil, Hungary and Indonesia.

During 2002, as a result of El Paso's efforts to enhance its liquidity
position, we sold reserves totaling 1.6 Tcfe to various third parties. The
reserves sold were primarily located in Colorado, Texas, Utah and western
Canada.

There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond Production's control.
The reserve data represents only estimates. Reservoir engineering is a
subjective process of estimating underground accumulations of natural gas and
oil that cannot be measured in an exact manner. The accuracy of any reserve
estimate is a function of the quality of available data and of engineering and
geological interpretations and judgment. As a result, estimates of different
engineers often vary. Estimates are subject to revision based upon a number of
factors, including reservoir performance, prices, economic conditions and
government restrictions. In addition, results of drilling, testing and
production subsequent to the date of an estimate may justify revision of that
estimate. Reserve estimates are often different from the quantities of natural
gas and oil that are ultimately recovered. The meaningfulness of reserve
estimates is highly dependent on the accuracy of the assumptions on which they
were based. In general, the volume of production from natural gas and oil
properties owned by Production declines as reserves are depleted. Except to the
extent Production conducts successful exploration and development activities or
acquires additional properties containing proved reserves, or both, the proved
reserves of Production will decline as reserves are produced. For further
discussion of our reserves, see Part II, Item 8, Financial Statements and
Supplementary Data, Note 22.

6

Wells and Acreage

The following table details Production's gross and net interest in
developed and undeveloped onshore, offshore, coal seam and international acreage
at December 31, 2002. Any acreage in which Production's interest is limited to
owned royalty, overriding royalty and other similar interests is excluded.

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(1) Gross interest reflects the total acreage we participated in, regardless of
our ownership interests in the acreage.
(2) Net interest is the aggregate of the fractional working interest that we
have in our gross acreage.

The U.S. domestic net developed acreage is concentrated primarily in the
Gulf of Mexico (49 percent), Utah (32 percent), and Texas (16 percent).
Approximately 34 percent, 29 percent and 19 percent of our total U.S. net
undeveloped acreage is held under leases that have minimum remaining primary
terms expiring in 2003, 2004 and 2005. During 2002, we sold approximately
345,180 net developed and 519,752 net undeveloped acres in Colorado, Texas, Utah
and western Canada as a result of El Paso's efforts to enhance its liquidity
position.

The following table details Production's working interests in onshore,
offshore, coal seam and international natural gas and oil wells at December 31,
2002:

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(1) Gross interest reflects the total number of wells we participated in,
regardless of our ownership interests in the wells.
(2) Net interest is the aggregate of the fractional working interest that we
have in our gross wells.

During 2002, as a result of El Paso's efforts to enhance its liquidity
position, we sold approximately 1,680 net wells in Colorado, Texas, Utah, and
western Canada.

7

The following table details Production's exploratory and development wells
drilled during the years 2000 through 2002:

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(1) Includes international operations in Australia, Brazil, Hungary and
Indonesia.

The information above should not be considered indicative of future
drilling performance, nor should it be assumed that there is any correlation
between the number of productive wells drilled and the amount of natural gas and
oil that may ultimately be recovered.

Net Production, Sales Prices, Transportation and Production Costs

The following tables detail Production's net production volumes, average
sales prices received, average transportation costs, average production costs
and production taxes associated with the sale of natural gas and oil for each of
the three years ended December 31:

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(1) Prices are stated before transportation costs.

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(1) Prices are stated before transportation costs.

(2) Production costs include direct lifting costs (labor, repairs and
maintenance, materials and supplies) and the administrative costs of field
offices, insurance and property and severance taxes.

9

Acquisition, Development and Exploration Expenditures

The following table details information regarding Production's costs
incurred in its development, exploration and acquisition activities for each of
the three years ended December 31:

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(1) Includes international operations in Australia, Brazil, Hungary and
Indonesia.

10

The table below details approximate amounts spent to develop proved
undeveloped reserves that were included in our reserve report as of January 1 of
each year:

Regulatory and Operating Environment

Production's natural gas and oil activities are regulated at the federal,
state and local levels, as well as internationally by the countries around the
world in which Production does business. These regulations include, but are not
limited to, the drilling and spacing of wells, conservation, forced pooling and
protection of correlative rights among interest owners. Production is also
subject to governmental safety regulations in the jurisdictions in which it
operates.

Production's domestic operations under federal natural gas and oil leases
are regulated by the statutes and regulations of the U.S. Department of the
Interior that currently impose liability upon lessees for the cost of
environmental impacts resulting from their operations. Royalty obligations on
all federal leases are regulated by the Minerals Management Service, which has
promulgated valuation guidelines for the payment of royalties by producers.
Production's international operations are subject to environmental regulations
administered by foreign governments, which include political subdivisions and
international organizations. These domestic and international laws and
regulations relating to the protection of the environment affect Production's
natural gas and oil operations through their effect on the construction and
operation of facilities, drilling operations, production or the delay or
prevention of future offshore lease sales. We believe that our operations are in
material compliance with the applicable requirements. In addition, we maintain
insurance on behalf of Production for sudden and accidental spills and oil
pollution liability.

Production's business has operating risks normally associated with the
exploration for and production of natural gas and oil, including blowouts,
cratering, pollution and fires, each of which could result in damage to life or
property. Offshore operations may encounter usual marine perils, including
hurricanes and other adverse weather conditions, governmental regulations and
interruption or termination by governmental authorities based on environmental
and other considerations. Customary with industry practices, we maintain
insurance coverage on behalf of Production with respect to potential losses
resulting from these operating hazards.

Markets and Competition

Our Production segment primarily sells its natural gas to third parties
through the trading group of El Paso at spot market prices. As a result of El
Paso's plan to exit the energy trading business announced in November 2002, our
Production segment is currently evaluating how it will sell its production in
the future. Alternatives being considered include whether to cancel its
agreement with El Paso's trading group and assume responsibility for natural gas
sales to third parties or enter into new marketing agreements with third parties
engaged in the marketing of natural gas. Production sells its natural gas
liquids at market prices under monthly or long-term contracts and its oil
production at posted prices, subject to adjustments for gravity and
transportation. Production also engages in hedging activities on its natural gas
and oil production to stabilize its cash flows and reduce the risk of downward
commodity price movements on sales of its production. This is achieved primarily
through natural gas and oil swaps. Under our hedging program, we may hedge up to
50 percent of our anticipated production for a rolling 12-month forward period.

The natural gas and oil business is highly competitive in the search for
and acquisition of additional reserves and in the sale of natural gas, oil and
natural gas liquids. Production's competitors include major and intermediate
sized natural gas and oil companies, independent natural gas and oil operations
and individual producers or operators with varying scopes of operations and
financial resources. Competitive factors include

11

price, contract terms and quality of service. Ultimately, our future success in
the production business will be dependent on our ability to find or acquire
additional reserves at costs that allow us to remain competitive.

FIELD SERVICES SEGMENT

Our Field Services segment provides customers with wellhead-to-mainline
services, including natural gas gathering, products extraction, fractionation,
dehydration, purification, compression and transportation of natural gas and
NGL. It also provides well-ties and real-time information services, including
electronic wellhead gas flow measurement.

Field Services' assets include natural gas gathering and NGL pipelines,
treating, processing and fractionation facilities, in the south Texas, south
Louisiana, Mid-Continent and Rocky Mountain regions.

In May 2002, we sold our Dragon Trail processing plant and in November
2002, we sold our 14.4 percent interest in the Aux Sable NGL plant. In December
2002, we sold our Natural Buttes and Ouray gas gathering facilities which
included 250 miles of natural gas gathering pipelines with approximately 200
MMcf/d of capacity. These assets gathered 146 BBtu/d for the year ended December
31, 2002. Also in December 2002, we sold our 50 percent interest in the Blacks
Fork Gas Processing Company which owns the Blacks Fork natural gas processing
plant in Wyoming. In January 2003, we sold several of our small gathering
systems located in Wyoming, which included 500 miles of natural gas gathering
pipelines with a capacity of 325 MMcf/d. These assets gathered 145 BBtu/d for
the year ended December 31, 2002. In March 2003, we received approval to sell
our remaining assets in the Mid-Continent region. These assets primarily include
our Greenwood, Hugoton, Keyes and Mocane natural gas gathering systems, our
Sturgis, Mocane and Lakin processing plants and our processing arrangements at
three additional processing plants. We expect this sale to close by the end of
2003.

The following tables provide information on Field Services' natural gas
gathering and transportation facilities, its processing facilities and the
facilities of its equity method investees:

Regulatory Environment

We are subject to the Natural Gas Pipeline Safety Act of 1968, the
Hazardous Liquid Pipeline Safety Act and various environmental statutes and
regulations. Each of our pipelines has continuing programs designed to keep the
facilities in compliance with pipeline safety and environmental requirements,
and we believe that these systems are in material compliance with the applicable
requirements.

Markets and Competition

Field Services competes with major interstate and intrastate pipeline
companies in transporting natural gas and NGL. Field Services also competes with
major integrated energy companies, independent natural gas gathering and
processing companies, natural gas marketers and oil and natural gas producers in
gathering and processing natural gas and NGL. Competition for throughput and
natural gas supplies is based on a number or factors, including price,
efficiency of facilities, gathering system line pressures, availability of
facilities near drilling activity, service and access to favorable downstream
markets.

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MERCHANT ENERGY SEGMENT

Our Merchant Energy segment consists of two primary divisions: global power
and petroleum.

Global Power

Our global power division includes the ownership and operation of domestic
and international power generation facilities. We own or have interests in 19
power plants in 8 countries. These plants represent 4,378 gross megawatts of
generating capacity, 87 percent of which is sold under power purchase or tolling
agreements with terms in excess of five years. Of these facilities, 37 percent
are natural gas fired and 63 percent are a combination of coal, NGL and other
fuels. Internationally, our focus is on building and acquiring energy
infrastructure in developed economies, and to a lesser degree in selected
emerging markets. Our primary international areas of focus historically have
included Asia and Central America.

Detailed below are our generating capacity by power facility for our power
plants as of December 31, 2002:

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(1) Gross megawatts represent the tested generating capacity of these
facilities.

Detailed below are our power generation projects, by region as of December
31, 2002:

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(1) Gross megawatts represent the tested generating capacity of these
facilities.
(2) Net megawatts represent our net ownership in the facilities.

Petroleum

In February 2003, El Paso announced its intent to sell substantially all of
our petroleum business (with the exception of our Aruba refinery) since it is
not core to our primary natural gas business.

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Our existing petroleum division: (i) owns or has interests in four crude
oil refineries and five chemical production facilities; (ii) has petroleum
terminalling and related marketing operations; and (iii) has blending and
packaging operations that produce and distribute a variety of lubricants and
automotive related products. Of the four refineries we own, we operate three of
them. The three refineries we operate have a throughput capability of
approximately 438 MBbls of crude oil per day to produce a variety of gasolines,
diesel fuels, asphalt, industrial fuels and other products. Our chemical
facilities have a production capability of 3,800 tons per day and produce
various industrial and agricultural products.

In 2002, our refineries operated at 64 percent of their average combined
capacity, at 70 percent in 2001 and at 93 percent in 2000. The aggregate sales
volumes at our wholly owned refineries were approximately 110 MMBbls in 2002,
131 MMBbls in 2001 and 182 MMBbls in 2000. Of our total refinery sales in 2002,
38 percent was gasoline, 41 percent was middle distillates, such as jet fuel,
diesel fuel and home heating oil, and 21 percent was heavy industrial fuels and
other products.

The following table presents average daily throughput and storage capacity
at our wholly owned refineries at December 31:

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(1) In June 2001, we leased our Corpus Christi refinery to Valero Energy
Corporation for 20 years. In February 2003, Valero exercised its option to
purchase the plant and related assets. These volumes only reflect those
produced prior to our lease of the facilities.

Our chemical plants produce agricultural fertilizers, gasoline additives
and other industrial products from facilities in Nevada, Oregon and Wyoming. The
following table presents sales volumes from our wholly owned chemical facilities
in the U.S. for each of the three years ended December 31:

Since January 2003, we have sold the majority of our interests in our
Florida petroleum terminals, our tug and barge operations, and all of our
interests in the Corpus Christi refinery. We also announced the sale of our
leasehold crude business and asphalt operations. We expect to sell the rest of
the assets associated with our petroleum business in 2003, with the exception of
the Aruba refinery.

Regulatory Environment

Merchant Energy's domestic power generation activities are regulated by the
FERC under the Federal Power Act with respect to its rates, terms and conditions
of service. In addition, exports of electricity outside of the U.S. must be
approved by the Department of Energy. Merchant Energy's cogeneration power
production activities are regulated by the FERC under the Public Utility
Regulatory Policies Act (PURPA) with respect to rates, procurement and provision
of services and operating standards. Its power generation and refining, chemical
and petroleum activities are also subject to federal, state and local
environmental regulations. We believe that our operations are in material
compliance with the applicable requirements.

14

Merchant Energy's foreign operations are regulated by numerous governmental
agencies in the countries in which these projects are located. Many of the
countries in which Merchant Energy conducts and will conduct business have
recently developed or are developing new regulatory and legal structures to
accommodate private and foreign-owned businesses. These regulatory and legal
structures and their interpretation and application by administrative agencies
are relatively new and sometimes limited. Many detailed rules and procedures are
yet to be issued, and we expect that the interpretation of existing rules in
these jurisdictions will evolve over time. We believe that our operations are in
material compliance with all environmental laws and regulations in the
applicable foreign jurisdictions.

Markets and Competition

During 2002, Merchant Energy's activities served over 1,400 suppliers and
2,900 customers around the world. Merchant Energy's businesses operate in a
highly competitive environment. Its primary competitors include:

- affiliates of major oil and natural gas producers;

- multi-national energy infrastructure companies;

- large domestic and foreign utility companies;

- affiliates of large local distribution companies;

- affiliates of other interstate and intrastate pipelines;

- independent energy marketers and power producers with varying scopes of
operations and financial resources; and

- independent refining and chemical companies.

Merchant Energy competes on the basis of price, operating efficiency,
technological advances, experience in the marketplace and counterparty credit.
Each market served by Merchant Energy is influenced directly or indirectly by
energy market economics.

Many of Merchant Energy's power generation facilities sell power pursuant
to long-term agreements with investor-owned utilities in the U.S. The terms of
its power purchase agreements for its facilities are such that Merchant Energy's
revenues from these facilities are not significantly impacted by competition
from other sources of generation. The power generation industry is rapidly
evolving and regulatory initiatives have been adopted at the federal and state
level aimed at increasing competition in the power generation business. As a
result, it is likely that when the power purchase agreements expire, these
facilities will be required to compete in a significantly different market in
which operating efficiency and other economic factors will determine success.
Merchant Energy is likely to face intense competition from generation companies
as well as from the wholesale power markets.

ENVIRONMENTAL

A description of our environmental activities is included in Part II, Item
8, Financial Statements and Supplementary Data, Note 16, and is incorporated
herein by reference.

EMPLOYEES

As of March 26, 2003, we had approximately 3,060 full-time employees, of
which 532 are subject to collective bargaining agreements.

15

ITEM 2. PROPERTIES

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

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

ITEM 3. LEGAL PROCEEDINGS

A description of our legal proceedings is included in Part II, Item 8,
Financial Statements and Supplementary Data, Note 16, and is incorporated herein
by reference.

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

Item 4, Submission of Matters to a Vote of Security Holders, has been
omitted from this report pursuant to the reduced disclosure format permitted by
General Instruction I to Form 10-K.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

All of our common stock, par value $1 per share, is owned by El Paso and,
accordingly, there is no public trading market for our common stock.

ITEM 6. SELECTED FINANCIAL DATA

Item 6, Selected Financial Data, has been omitted from this report pursuant
to the reduced disclosure format permitted by General Instruction I to Form
10-K.

16

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

The information required by this Item is presented in a reduced disclosure
format permitted by General Instruction I to Form 10-K. The Notes to
Consolidated Financial Statements contain information that is pertinent to the
following analysis, including a discussion of our significant accounting
policies.

RESULTS OF OPERATIONS

We use earnings before interest and income taxes (EBIT) to assess the
operating results and effectiveness of our business segments. We define EBIT as
operating income, adjusted for earnings from unconsolidated affiliates and other
miscellaneous non-operating items. Items that are not included in this measure
are financing costs, including interest and debt expense, income taxes,
discontinued operations, extraordinary items and cumulative effect of accounting
changes. The following is a reconciliation of our operating results to EBIT and
loss from continuing operations for the years ended December 31:

We believe EBIT is a useful measurement for our investors because it
provides information that can be used to evaluate the effectiveness of our
businesses and investments from an operational perspective, exclusive of the
costs to finance those activities and exclusive of income taxes, neither of
which are directly relevant to the efficiency of those operations. This
measurement may not be comparable to measurements used by other companies and
should not be used as a substitute for net income or other performance measures
such as operating cash flow.

17

OVERVIEW OF RESULTS OF OPERATIONS

Below are our results of operations (as measured by EBIT), by segment for
the years ended December 31, 2002 and 2001. These results include the impacts of
restructuring and merger-related costs, asset impairments, other charges, and
gains (losses) on long-lived assets, which are discussed further in Item 8,
Financial Statements and Supplementary Data, Notes 3, 4 and 20. See Item 8,
Financial Statements and Supplementary Data, Note 18, for a reconciliation of
our operating results to EBIT by segment.

SEGMENT RESULTS

Our four segments: Pipelines, Production, Field Services and Merchant
Energy are strategic business units that offer a variety of different energy
products and services, each requires different technology and marketing
strategies. Below is a discussion and analysis of the operating results of each
of our business segments. These results include the impact of the restructuring
and merger-related costs, asset impairments and other charges discussed above
for all years presented.

PIPELINES

Our Pipelines segment consists of interstate natural gas transmission,
storage, gathering and related services in the U.S. and internationally. Our
interstate natural gas transportation systems face varying degrees of
competition from other pipelines, as well as from alternate energy sources used
to generate electricity, such as hydroelectric power, nuclear, coal and fuel
oil.

We are regulated by the FERC, which regulates the rates we can charge our
customers. These rates are a function of our costs of providing services to our
customers, and include a return on our invested capital. As a result, our
financial results have historically been relatively stable; however, they can be
subject to volatility due to factors such as weather, changes in natural gas
prices and market conditions, regulatory actions, competition and the
credit-worthiness of our customers. In addition, our ability to extend our
existing customer contracts or re-market expiring contracted capacity is
dependent on competitive alternatives, the regulatory environment at the
federal, state and local levels and market supply and demand factors at the
relevant dates these contracts are extended or expire. The duration of new or
re-negotiated contracts will be affected by current prices, competitive
conditions and judgments concerning future market trends and volatility. Subject
to regulatory constraints, we attempt to re-contract or re-market our capacity
at the maximum rates allowed under our tariffs, although we, at times, discount
these rates to remain competitive. The level of discount varies for each of our
pipeline systems.

18

In November 2002, we sold 12.3 percent of our 14.4 percent equity interest
in the Alliance pipeline system, and net proceeds were $141 million. We
completed the sale of our remaining equity interest in Alliance during the first
quarter of 2003. Income earned on our investment in Alliance for the year ended
December 31, 2002 and 2001, was approximately $21 million and $23 million.

Results of operations of the Pipelines segment were as follows for the
years ended December 31:

PIPELINE SEGMENT RESULTS

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

(1) Throughput volumes exclude those related to pipeline systems sold in
connection with Federal Trade Commission orders related to our merger with
El Paso including the Empire State and Iroquois pipeline investments.
Throughput volumes exclude intrasegment activities.

Operating revenues for the year ended December 31, 2002, were $128 million
lower than in 2001. This decrease was due to a $49 million decrease from natural
gas sales, gathering and processing activities due to CIG's sale of the
Panhandle field and other production properties in July 2002, a $33 million
decrease due to reduced natural gas and liquids sales due to lower prices in
2002, and a $28 million decrease in sale of excess natural gas in 2001. Also
contributing to the decrease were $22 million lower transportation revenues due
to milder weather in 2002, $19 million from lower resales of natural gas
purchased from the Dakota gasification facility and $6 million lower 2002 sales
of base gas from abandoned storage fields. These decreases were partially offset
by higher reservation revenues of $30 million primarily due to system expansion
projects placed in service in 2001.

Operating expenses for the year ended December 31, 2002, were $352 million
lower than in 2001 primarily as a result of merger-related costs of $192 million
incurred in 2001 to relocate our ANR pipeline operations from Detroit, Michigan
to Houston, Texas, costs for employee benefits, severance retention, transition
charges and other miscellaneous charges. Also contributing to the decrease were
$24 million from lower gas costs for our system supply purchases resulting from
lower natural gas prices and volumes, $27 million from lower benefit costs and
cost efficiencies following our merger with El Paso, $19 million from lower
prices on gas purchases from the Dakota gasification facility, $18 million from
lower amortization of goodwill due to the implementation of SFAS No. 142 in
2002, a $22 million decrease in operating expenses due to CIG's sale of
Panhandle field and other production properties in July 2002, $11 million due to
a gain on the sale of pipeline expansion rights in February 2002, and $5 million
lower corporate overhead allocations.

Other income for the year ended December 31, 2002, was $21 million higher
than in 2001. The increase was due to the resolution of uncertainties associated
with the sales of our interests in the Empire State, Iroquois pipeline systems,
and our Gulfstream pipeline project in 2001 of $11 million and higher equity
earnings in 2002 of $8 million on our Great Lakes Gas Transmission investment.
These increases were partially offset by lower equity earnings of $6 million on
Empire State and Iroquois pipeline systems due to the sale of our interests in
2001.

PRODUCTION

The Production segment conducts our natural gas and oil exploration and
production activities. Our operating results are driven by a variety of factors
including the ability to locate and develop economic natural

19

gas and oil reserves, extract those reserves with minimal production costs, sell
the products at attractive prices and operate at the lowest total cost level
possible.

Production has historically engaged in hedging activities on its natural
gas and oil production to stabilize cash flows and to reduce the risk of
downward commodity price movements on its production. This is achieved primarily
through natural gas and oil swaps. In the past, our stated goal was to hedge
approximately 75 percent of our anticipated current year production,
approximately 50 percent of our anticipated succeeding year production and a
lesser percentage thereafter. In May 2002, we modified this hedging strategy.
Under the modified strategy, we may hedge up to 50 percent of our anticipated
production for a rolling 12-month forward period. This modification of our
hedging strategy will increase our exposure to changes in commodity prices which
could result in significant volatility in our reported results of operations,
financial position and cash flows from period to period. As of December 31,
2002, we have hedged approximately 83 million MMBtu's of our anticipated natural
gas production for 2003 at a NYMEX Henry Hub price of $4.36 per MMBtu before
regional price differentials and transportation costs.

During 2002, we continued an active onshore and offshore development
drilling program to capitalize on our land and seismic holdings. This
development drilling was done to take advantage of our large inventory of
drilling prospects and to develop our proved undeveloped reserve base. We also
completed asset dispositions in Colorado, Utah, western Canada and Texas as part
of El Paso's liquidity enhancement plan. Primarily due to our asset
dispositions, we have a lower reserve base at January 1, 2003 than we did at
January 1, 2002. See Item 8, Financial Statements and Supplementary Data, Note
22, for a discussion of our natural gas and oil reserves. Since our depletion
rate is determined under the full cost method of accounting, a lower reserve
base coupled with additional capital expenditures in the full cost pool will
result in a higher depletion rate in future periods. For the first quarter of
2003, we expect our domestic unit of production depletion rate to be
approximately $1.87 per Mcfe.

We currently expect to reduce our total capital expenditures from
approximately $1.1 billion in 2002 to approximately $600 million in 2003. We
continually evaluate our capital expenditure program and this estimate is
subject to change based on market conditions. We will continue to pursue
strategic acquisitions of production properties and the development of projects
subject to acceptable returns.

Below are the operating results and analysis of these results for the years
ended December 31:

- ---------------------
(1) Includes production costs, depletion, depreciation and amortization, ceiling
test charges, merger related costs, gains (losses) on long-lived assets,
changes in accounting estimates, corporate overhead, general and
administrative expenses and severance and other taxes.

20

- ---------------------
(1) Prices are stated before transportation costs.

For the year ended December 31, 2002, operating revenues were $525 million
lower than in 2001. A 32 percent decrease in natural gas volumes and a 26
percent decrease in natural gas prices before hedges and transportation costs
account for $799 million of the decrease in revenues, offset by a $326 million
favorable variance from natural gas hedging activity in 2002 when compared to
2001. The decline in natural gas volumes is primarily attributed to the sale of
properties in Colorado, Utah and Texas. A nine percent decrease in oil,
condensate and liquids volumes and an 11 percent decrease in their prices before
hedges and transportation costs resulted in a $38 million decrease in revenues.

Transportation and net product costs for the year ended December 31, 2002,
were $4 million lower than in 2001 primarily due to a lower percentage of gas
volumes subject to transportation fees, offset by higher costs incurred to meet
minimum payments on pipeline agreements.

Operating expenses for the year ended December 31, 2002, were $725 million
higher than in 2001 primarily due to a $702 million loss recognized in December
2002 on the sale of our natural gas and oil properties in Utah. A loss was
recognized on this sale because the reserves sold significantly altered the
relationship between capitalized costs and proved reserves. Also contributing to
the increase in expenses were non-cash full cost ceiling test charges totaling
$245 million incurred in 2002 for our Canadian full cost pool and other
international properties, primarily in Brazil and Australia, offset by 2001
non-cash full cost ceiling test charges on international properties totaling
$115 million. Also contributing to the increase in 2002 expenses were a $4
million charge for a Canadian intangible asset impairment, and a higher
corporate overhead allocation of $43 million partially offset by decreased
oilfield service costs of $31 million. Partially offsetting the increase in
expenses was the unit of production depletion expense which was lower by $9
million with $128 million resulting from lower production volumes in 2002 offset
by $119 million due to higher depletion rates in 2002. The higher depletion rate
resulted from higher capitalized costs in the full cost pool and a lower reserve
base. Further offsetting the increase in expenses were merger related costs of
$45 million and asset impairments of $16 million incurred in 2001 related to our
combined operations with El Paso and $10 million for write-downs of materials
and supplies recognized in 2001 resulting from the reduction in inventory values
due to the implementation of consistent operating standards, strategies and
plans following the merger with El Paso. For a discussion of merger-related
costs, gains and losses on long-lived assets and changes in accounting
estimates, see Item 8, Financial Statements and Supplementary Data, Notes 3, 4
and 5. In addition, the increase in expense was offset by $46 million of lower
severance and other taxes in 2002. The severance taxes decreased primarily
because of lower natural gas volumes and prices, and for credits taken in 2002
for qualified natural gas wells.

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FIELD SERVICES

Our Field Services segment provides a variety of midstream services,
including gathering and transportation of natural gas, processing and
fractionation of natural gas, NGL and natural gas derivative products, such as
butane, ethane and propane.

During 2002, we identified midstream assets to be sold to third parties as
part of El Paso's plan to strengthen its capital structure and enhance its
liquidity. See Item 8, Financial Statements and Supplementary Data, Note 2 for
further discussion of asset sales completed in 2002.

In May 2002, we sold our Dragon Trail processing plant and in November
2002, we sold our 14.4 percent interest in the Aux Sable NGL plant. In December
2002, we sold our Natural Buttes and Ouray gas gathering facilities. Also in
December 2002, we sold our 50 percent interest in the Blacks Fork Gas Processing
Company which owns the Blacks Fork natural gas processing plant in Wyoming. In
January 2003, we sold several of our small gathering systems located in Wyoming.
In March 2003, we received approval to sell our assets in the Mid-Continent
region. These assets primarily include our Greenwood, Hugoton, Keyes and Mocane
natural gas gathering systems, our Sturgis, Mocane and Lakin processing plants
and our processing arrangements at three additional processing plants. We expect
this sale to close by the end of 2003. After this sale is completed, our
remaining assets will consist primarily of processing facilities in the south
Texas, south Louisiana and Rocky Mountain regions.

As a result of our asset sales and the resulting decline in our gathering
and treating activities, we expect our future EBIT to decrease considerably.

We attempt to balance our earnings from our operating activities through a
combination of fixed-fee based and market-based services. A majority of our
gathering and transportation operations earn margins from fixed-fee-based
services. However, some of our operations earn margins from market-based rates.
Revenues from these market-based rate services are the product of the market
price, usually related to the monthly natural gas price index and the volume
gathered.

Processing and fractionation operations earn a margin based on fixed-fee
contracts, percentage-of-proceeds contracts and make-whole contracts.
Percentage-of-proceeds contracts allow us to retain a percentage of the product
as a fee for processing or fractionation service. Make-whole contracts allow us
to retain the extracted liquid products and return to the producer a Btu
equivalent amount of natural gas. Under our percentage-of-proceeds contracts and
make-whole contracts, we may have more sensitivity to price changes during
periods when natural gas and NGL prices are volatile.

Our operating results and an analysis of those results are as follows for
years ended December 31:

22

Total gross margins for the year ended December 31, 2002, were $43 million
lower than in 2001. Margins decreased by approximately $37 million primarily due
to lower NGL prices in 2002 and natural declines in production in 2002, which
unfavorably impacted our volumes and margins in the Rocky Mountain and south
Louisiana regions. We also experienced lower margins of approximately $6 million
related to the sale of our Dragon Trail processing plant in May 2002.

Operating expenses for the year ended December 31, 2002, were $55 million
lower than in 2001. The decrease was due to gains in 2002 on the sales of our
Natural Buttes and Ouray natural gas gathering systems and our Dragon Trail
processing plant of $26 million and $10 million, a decrease in merger-related
costs of $13 million in connection with our 2001 merger with El Paso and a
change in our 2001 estimated environmental remediation liabilities of $9
million. Also contributing to the decrease was $14 million of lower operating
and maintenance expenses as a result of the sale of our Dragon Trail processing
plant and our cost reduction plan in 2002. The decrease in operating expense was
partially offset by a $14 million loss associated with our write-down of
goodwill related to our SFAS No. 142 goodwill procedures.

Other income for the year ended December 31, 2002, was $70 million lower
than in 2001. The decrease was due to the losses on the sale in 2002 of our
investment in the Aux Sable NGL plant and our investment in the Blacks Fork
natural gas processing plant of $47 million and $3 million. Also contributing to
the decrease in other income for 2002 was a $13 million gain on the sale of our
investment in Deepwater Holdings in October 2001 and $6 million of lower equity
earnings from Deepwater Holdings as a result of the sale of our interest to El
Paso Energy Partners, an affiliate, in October 2001.

MERCHANT ENERGY

Our Merchant Energy segment consists of two primary divisions: global power
and petroleum. Early in 2003, El Paso announced its intent to exit substantially
all of our petroleum activities (excluding our Aruba refinery).

Below are Merchant Energy's operating results and an analysis of those
results for the years ended December 31:

GLOBAL POWER

Our global power division includes the ownership and operation of domestic
and international power generating facilities. In most cases, we partially own
our power generating facilities and account for them using the equity method.

23

Power Contract Restructuring Activities. Many of our domestic power plants
have long-term power sales contracts with regulated utilities that were entered
into under the Public Utility Regulatory Policies Act of 1978 (PURPA). The power
sold to the utility under these PURPA contracts is required to be delivered from
a specified power generation plant at power prices that are usually
significantly higher than the cost of power in the wholesale power market. Our
cost of generating power at these PURPA power plants is typically higher than
the cost we would incur by obtaining the power in the wholesale power market,
principally because the PURPA power plants are less efficient than newer power
generation facilities.

Typically, in a power contract restructuring, the PURPA power sales
contract is amended so that the power sold to the utility does not have to be
provided from the specific power plant. Because we have been able to buy lower
cost power in the wholesale power market, we have the ability to reduce the cost
paid by the utility, thereby inducing the utility to enter into the power
contract restructuring transaction. Following a contract restructuring, the
power plant operates on a merchant basis, which means that it is no longer
dedicated to one buyer and will operate only when power prices are high enough
to make its operation economical. In addition, we or our affiliates, may assume,
and in the case of our Eagle Point Cogeneration facility, our affiliate, did
assume, the business and economic risks of supplying power to the utility to
satisfy the delivery requirements under the restructured power contract over its
term. When this risk is assumed, its risk is managed by entering into
transactions to buy power from third parties over the life of the contract.
Power contract restructurings generally result in a higher return in our power
generation business because we can deliver reliable power at lower prices than
our cost to generate power at these PURPA power plants. In addition, we can use
the restructured contracts as collateral to obtain financing at a cost that is
comparable to, or lower than, our existing financing costs.

During 2002, we completed restructurings of several long-term power
contracts held by our unconsolidated affiliates or, in some cases, held by us.
As a result of our credit downgrades, El Paso's decision to exit its trading
business and disruption in the capital markets, it is unlikely we will pursue
additional power contract restructurings in the near term. For a further
discussion of these activities, see Item 8, Financial Statements and
Supplementary Data, Note 11.

GLOBAL POWER DIVISION RESULTS

Gross margins consist of revenues from our power plants and the net results
from our power restructuring activities. The cost of fuel used in the power
generation process is included in operating expenses. For the year ended
December 31, 2002, gross margin for the global power division was $640 million
higher than in 2001. Gross margin from power contract restructurings comprised
$486 million of the increase. During 2002, we completed power contract
restructurings or contract terminations at our Eagle Point Cogeneration and
Nejapa power plants. The Eagle Point restructuring transaction, completed in
March 2002, was our most significant power contract restructuring transaction
and contributed $359 million to our net 2002 results.

The Eagle Point restructuring involved several steps and all revenues,
expenses, fees and impairments related to the transaction were reported in our
2002 gross margin. First, we amended the existing PURPA power sales contract
with Public Service Electric and Gas (PSEG) to eliminate the requirement that
power be delivered specifically from the Eagle Point power plant. This amended
contract has fixed prices with stated increases over the 14-year term that range
from $85 per MWh to $126 per MWh. We entered into the amended power sales
contract through a consolidated subsidiary, UCF. UCF was created to hold and
execute the terms of the restructured power sales contract, to enter into a
supply contract to meet the requirements of

24

the restructured agreement and to monetize the net cash flows of these contracts
by issuing debt. In keeping with its purpose, UCF entered into a power supply
agreement with El Paso's energy trading division (EPME) who usually participates
in our power restructuring activities by taking on the obligation to supply
power. The terms of the EPME power supply contract were identical to the amended
restructured power sales contract, with the exception of price, which was set at
$37 per MWh over its 14-year term.

For credit enhancement purposes, in anticipation of the financing
transaction associated with the restructuring, UCF terminated the EPME supply
contract in the second quarter of 2002 and replaced it with a supply contract
with a Morgan Stanley affiliate. UCF entered into the Morgan Stanley contract
solely for the purpose of reducing the cost of debt UCF would issue.

The actions taken to restructure the contract required us to mark the
contract to its fair value. As a result, we recorded non-cash revenue
representing the estimated fair value of the derivative contracts of
approximately $898 million. We also amended or terminated other ancillary
agreements associated with the cogeneration facility, such as gas supply and
transportation agreements, a steam contract and existing financing agreements.
We also paid $103 million to the utility to terminate the original PURPA
contract. Also included in our operating results for 2002 were a $98 milli