<PAGE>   1

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                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                   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, 2000 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
                       (FORMERLY THE COASTAL CORPORATION)
             (Exact name of registrant as specified in its charter)

<TABLE>
<S>                                            <C>
                   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)
</TABLE>

       Registrant's telephone number, including area code: (713) 420-2131

          Securities registered pursuant to Section 12(b) of the Act:

<TABLE>
<CAPTION>
                                                               NAME OF EACH EXCHANGE
TITLE OF EACH CLASS                                             ON WHICH REGISTERED
-------------------                                            ---------------------
<S>                                                           <C>
8.375% Coastal Trust Preferred Securities issued by Coastal
  Finance I
Growth PRIDES                                                 New York Stock Exchange
Income PRIDES
</TABLE>

        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, 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]
    Common Stock, par value $1.00 per share. Shares outstanding on March 19,
2001: 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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<PAGE>   2

                              EL PASO CGP COMPANY

                               TABLE OF CONTENTS

<TABLE>
<CAPTION>
                                      CAPTION                             PAGE
                                      -------                             ----
<S>         <C>                                                           <C>
                                    PART I

Item 1.     Business....................................................    1
Item 2.     Properties..................................................   17
Item 3.     Legal Proceedings...........................................   17
Item 4.     Submission of Matters to a Vote of Security Holders.........    *

                                   PART II

Item 5.     Market for Registrant's Common Equity and Related
            Stockholder Matters.........................................   18
Item 6.     Selected Financial Data.....................................    *
Item 7.     Management's Discussion and Analysis of Financial Condition
            and Results of Operations...................................   18
Item 7A.    Quantitative and Qualitative Disclosures About Market
            Risk........................................................   24
Item 8.     Financial Statements and Supplementary Data.................   26
Item 9.     Changes in and Disagreements with Accountants on Accounting
            and Financial Disclosure....................................   57

                                   PART III

Item 10.    Directors and Executive Officers of the Registrant..........   *
Item 11.    Executive Compensation......................................   *
Item 12.    Security Ownership of Certain Beneficial Owners and
            Management..................................................   *
Item 13.    Certain Relationships and Related Transactions..............   *

                                   PART IV

Item 14.    Exhibits, Financial Statement Schedules, and Reports on Form
            8-K.........................................................   57
            Signatures..................................................   59
</TABLE>

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

* 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:

<TABLE>
<S>      <C>
/d       = per day
Bbls     = barrels
Bcf      = billion cubic feet
Bcfe     = billion cubic feet of gas equivalents
Btu      = British thermal units
MMBtu    = million British thermal units
MBbls    = thousand barrels
MMBbls   = million barrels
Mcf      = thousand cubic feet
Mcfe     = thousand cubic feet of gas equivalents
MMcf     = million cubic feet
MMcfe    = million cubic feet of gas equivalents
</TABLE>

    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 is equal to six Mcf. Also, when
we refer to cubic feet measurements, all measurements are at 14.73 pounds per
square inch.

                                        i
<PAGE>   3

                                     PART I

ITEM 1. BUSINESS.

                                  INTRODUCTION

     In January 2001, we became a wholly owned subsidiary of El Paso Corporation
through our merger with a wholly owned El Paso subsidiary. In the merger, each
share of our common stock and Class A common stock was converted on a tax-free
basis into 1.23 shares of El Paso common stock. Our outstanding convertible
preferred stock was exchanged tax free for El Paso common stock on the same
basis as if the preferred stock had been converted into our common stock
immediately prior to the merger. El Paso issued a total of approximately 271
million shares of its common stock, including approximately 4 million shares
issued in exchange for our outstanding stock options.

     On January 30, 2001, we changed our name from The Coastal Corporation to El
Paso CGP Company.

     We are a Delaware corporation, incorporated in 1972 and originally founded
in 1955. We are a diversified energy company with operations in natural gas
gathering, marketing, processing, storage and transmission; petroleum refining,
marketing and chemicals; gas and oil exploration and production; coal mining;
and power.

                              NATURAL GAS SYSTEMS

     Our natural gas systems are involved in the production, purchase,
gathering, processing, transportation, and storage of natural gas. We also
market and sell natural gas to and for utilities, industrial customers,
marketers, producers, distributors, other pipeline companies and end users.

REGULATED GAS OPERATIONS

     ANR.  ANR Pipeline Company is involved in the open access transportation,
storage and gathering of natural gas owned by third parties. ANR's two
interconnected, large-diameter multiple pipeline systems transport natural gas
from gas-producing fields in Texas, Oklahoma, Louisiana, the Gulf of Mexico, and
Canada to markets in the Midwest and Northeast regions of the United States,
including the metropolitan areas of Detroit, Chicago, and Milwaukee.

     ANR's system consists of 10,600 miles of pipeline and 74 compressor
stations, with a design peak capacity of approximately 6.6 Bcf/d. During 2000,
ANR transported natural gas volumes averaging approximately 71 percent of its
capacity. Along its system, ANR also has approximately 202 Bcf of underground
working gas storage capacity, with a maximum daily delivery capacity of 3 Bcf.
Working gas storage capacity operated by ANR of 126.3 Bcf is available from five
owned and five leased underground storage facilities in Michigan. ANR also has
contracted rights for 75.4 Bcf of working gas storage capacity, of which 45.4
Bcf is provided by Blue Lake Gas Storage Company and 30 Bcf is provided by ANR
Storage Company.

     ANR has a 50 percent indirect interest in the East Breaks, High Island
Offshore, Stingray and U-T Offshore systems, all of which are located in the
Gulf of Mexico. ANR also owns an indirect 16 percent interest in the Iroquois
pipeline system that transports gas from Canada to the northeastern U.S. As a
result of the El Paso merger, ANR was required, under a Federal Trade Commission
consent order, to dispose of its interests in the U-T Offshore and Stingray
systems. These sales were completed in February 2001. Under that same consent
order, ANR will dispose of its 16 percent interest in the Iroquois Gas
Transmission System. The sale of ANR's interest in the Iroquois system is
expected to be completed in the first half 2001.

                                        1
<PAGE>   4

     Deliveries on the ANR system for the years 2000, 1999, and 1998 were as
follows:

<TABLE>
<CAPTION>
                       TOTAL SYSTEM     DAILY AVERAGE
YEAR                    DELIVERIES    SYSTEM DELIVERIES
----                   ------------   -----------------
                          (BCF)            (MMCF)
<S>                    <C>            <C>
2000                      1,352             3,694
1999                      1,362             3,732
1998                      1,354             3,710
</TABLE>

     CIG.  Colorado Interstate Gas Company is involved in the production,
purchase, gathering, processing, transportation, storage and sale of natural
gas. CIG's gas transmission system extends from natural gas production areas in
the Panhandle Field of Texas and is directly or indirectly connected to every
major supply basin in the Rocky Mountain region. CIG's pipeline system serves
two major markets, one along the Front Range of the Rocky Mountains in Colorado
and Wyoming and the second interconnects with other pipelines transporting gas
to California and the Midwest.

     CIG's principal transmission facilities consist of approximately 4,400
miles of pipeline and 56 compressor stations, with a design capacity of 2,290
MMcf/d. During 2000, CIG transported natural gas volumes averaging approximately
60 percent of its capacity. Along its system, CIG also has approximately 29 Bcf
of working gas storage capacity and owns four underground natural gas storage
fields; three located in Colorado and one in Kansas.

     Deliveries on the CIG system for the years 2000, 1999, and 1998 were as
follows:

<TABLE>
<CAPTION>
                                                           TOTAL SYSTEM     DAILY AVERAGE
                                                            DELIVERIES    SYSTEM DELIVERIES
YEAR                                                          (BCF)            (MMCF)
----                                                       ------------   -----------------
<S>                                                        <C>            <C>
2000.....................................................      485              1,325
1999.....................................................      454              1,245
1998.....................................................      480              1,315
</TABLE>

     In addition to its transmission and storage activities, CIG owns or
controls proved reserves that were estimated to total 202 Bcf, 228 Bcf, and 243
Bcf at December 31, 2000, 1999, and 1998. These estimates are based on a report
by Huddleston & Co., Inc., our independent engineers. CIG also maintains, for
its own account, 2.5 Bcf of natural gas in underground storage fields and has an
additional 37.8 Bcf of base natural gas in its four storage fields. From its
total reserves, primarily located in the Panhandle Field, CIG is committed to
sell 77 percent to Pioneer Natural Resources USA, Inc. The remaining production
may be sold to third parties.

     Wyoming Interstate. Wyoming Interstate Company, Ltd. owns an interstate
pipeline system located primarily in Wyoming. The Wyoming Interstate system
consists of approximately 400 miles of pipeline with a total design capacity of
1,157 MMcf/d. During 2000, Wyoming Interstate transported natural gas volumes
averaging approximately 75 percent of its capacity. The system has two
large-diameter pipelines that come together in northern Colorado to feed into
the CIG-Trailblazer interconnect on the 800-mile Trailblazer system and into
other interstate and intrastate pipelines at that interconnect.

     Alliance Pipeline. We own an approximate 14 percent interest in the
Alliance Pipeline. Alliance consists of approximately 2,300 miles of pipeline,
including lateral lines, with a design capacity of 1,325 MMcf/d and extends from
supply fields in western Canada to the Chicago area market center. Alliance
commenced service in late 2000.

     Great Lakes Gas Transmission. We own a 50 percent interest in Great Lakes
Gas Transmission, LP. Great Lakes owns a 2,100-mile pipeline with a design
capacity of 2,895 MMcf/d. The system extends from the Manitoba-Minnesota border
to an interconnection on the Michigan-Ontario border at St. Clair, Michigan.
During 2000, Great Lakes transported volumes averaging approximately 84 percent
of its capacity.

     ANR Storage. ANR Storage Company develops and operates underground natural
gas storage facilities. ANR Storage owns four underground storage facilities in
northern Michigan. These facilities have a working

                                        2
<PAGE>   5

storage capacity of approximately 56 Bcf, of which 30 Bcf is contracted by ANR.
In addition, ANR Storage has joint ownership interests in three storage
facilities located in Michigan and New York with a total working storage
capacity of approximately 65 Bcf. All of ANR Storage's jointly owned capacity is
under long-term contracts, including 45 Bcf contracted to ANR.

REGULATORY ENVIRONMENT

     Our interstate natural gas systems and our storage operations are regulated
by the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of
1938 and the Natural Gas Policy Act of 1978. Each system operates under separate
FERC approved tariffs that establish rates, terms, and conditions under which
each system provides services to its customers. Generally, FERC's authority
extends to:

     - transportation and storage of natural gas, rates and charges;

     - certification and construction of new facilities;

     - extension or abandonment of services and facilities;

     - maintenance of accounts and records;

     - depreciation and amortization policies;

     - acquisition and disposition of facilities;

     - initiation and discontinuation of services; and

     - various other matters.

     Our wholly owned and domestic investee pipelines have tariffs established
through filings with FERC and have a variety of terms and conditions, each of
which affects the pipeline's operations and its ability to recover fees for the
services it provides. By and large, changes to these fees or terms can only be
implemented upon approval by FERC.

     Our interstate pipeline systems are also subject to the Natural Gas
Pipeline Safety Act of 1968 that establishes pipeline and liquefied natural gas
plant safety requirements. We are also subject to environmental legislation and
regulations. Each of our systems has a continuing program of inspection designed
to keep all of our facilities in compliance with pollution control and pipeline
safety requirements. We believe that our systems are in substantial compliance
with the applicable requirements.

     We are also subject to regulation with respect to safety requirements in
the design, construction, operation and maintenance of our interstate natural
gas transmission and storage facilities by the U.S. Department of
Transportation. Additionally, we are subject to similar safety requirements from
the U.S. Department of Labor's Occupational Safety and Health Administration
related to our processing plants. Operations on U.S. government land are
regulated by the U.S. Department of the Interior.

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

     For further discussion of our regulatory matters, see Item 8, Financial
Statements and Supplementary Data, Note 15.

MARKETS AND COMPETITION

     Our natural gas interstate systems face varying degrees of competition from
alternative energy sources, such as electricity, hydroelectric power, coal, and
fuel oil. Also, the potential consequences of proposed and ongoing restructuring
and deregulation of the electric power industry are currently unclear.
Restructuring and deregulation may benefit the natural gas industry by creating
more demand for natural gas turbine generated electric power, or it may hamper
demand by allowing a more effective use of surplus electric capacity through
increased wheeling as a result of open access.
                                        3
<PAGE>   6

     In its historical market areas of Wisconsin and Michigan, ANR competes with
other interstate and intrastate pipeline companies and local distribution
companies in the transportation and storage of natural gas. ANR has been
successful in restructuring the service portfolios of a number of its major
Wisconsin customers. This restructuring has enabled ANR to extend contracts that
were set to expire in 2003, with the restructured contracts providing for a
combined winter maximum daily quantity of 674 MMcf/d that will expire in 2008
and 2010. ANR continues to work with its largest customer, Wisconsin Gas
Company, to restructure and extend contracts that are set to expire in 2003.
However, Wisconsin Gas is a sponsor of the proposed Guardian Pipeline, which
received a FERC certificate on March 14, 2001, and that pipeline will directly
compete for a portion of this expiring capacity. ANR also has 900 MMcf/d of
capacity under contract with Michigan Consolidated Gas Company. Of that amount,
110 MMcf/d is due to expire in March 2002, another 175 MMcf/d will expire in
2003, and the remainder of the capacity will expire between 2006 and 2011.
Extensions of these contracts are under negotiation.

     ANR also faces competition in the Northeast markets from other interstate
pipelines serving electric generation and local distribution companies.

     CIG serves two major markets, its "on-system" market, consisting of the
utilities along the Front Range of the Rocky Mountains in Colorado and Wyoming,
and its "off-system" market, consisting of the transportation of Rocky Mountain
production from multiple supply basins to interconnections with other pipelines
bound for the Midwest or California. CIG faces different types of competition in
both markets. In the on-system market, competition comes from local supply in
the Denver-Julesburg basin, from an intrastate pipeline directly serving Denver,
and from off-system shippers who can deliver their gas in that market,
supplanting CIG transportation for utility customers. The primary criterion for
success in this market is the ability to serve a very volatile load reliably, at
a competitive price. In the off-system market, CIG faces competition in its
supply area from two major pipelines serving the California and Pacific
Northwest markets. It also faces competition from competitors whose supply is
produced in Texas, Oklahoma, and Kansas. These competitors can displace CIG
deliveries into the pipelines serving the Midwestern markets. The primary
criterion for success in this market is the strength of pricing differentials
between Wyoming and Oklahoma.

     CIG's full capacity is contracted under firm transportation agreements,
with the bulk of these agreements expiring within the next several years. The
largest portion of these agreements is with Public Service Company of Colorado
and will expire in the 2002 to 2005 timeframe. CIG is actively negotiating with
all shippers for contract renewal and is optimistic that its ability to serve
the Front Range market reliably and competitively, coupled with reasonably
strong pricing differentials affecting off-system markets, will result in
successful renewal of the expiring contracts. New firm transportation contracts
have not yet been executed for the bulk of the volumes involved, but CIG has
reached agreement in principle with Public Service Company to renew its
contracts at revenue levels close to historical levels.

     WIC's two lines are subject to different competitive forces. Both lines are
currently fully contracted and are subject to take-away capacity constraints at
their intersection in northern Colorado. Both of WIC's lines feed into the
Trailblazer system going east, the CIG system going south and other interstate
and intrastate pipelines connected at the CIG-Trailblazer interconnect. Due to
the full capacity demand on the Trailblazer system and the near capacity demand
on the CIG system, shippers on WIC's two lines must compete with each other for
scarce capacity to the markets of choice. On WIC's main line, contracts for
approximately 500 MMcf/d out of approximately 750 MMcf/d expire in 2003. Success
in renewing or replacing these contracts will depend on the availability of
eastbound capacity. WIC's contracts generally have between six and ten years
remaining.

UNREGULATED GAS OPERATIONS

     Our unregulated natural gas operations include our natural gas midstream
activities (gathering, processing, natural gas liquids pipelines and storage,
fractionation, gas supply, and gas and natural gas liquids marketing), marketing
and trading activities, and international pipeline operations.

     We own or operate for various affiliates domestic midstream assets in
Alabama, Colorado, Kansas, Louisiana, Mississippi, Oklahoma, Texas, Utah,
Wyoming and offshore in the Gulf of Mexico. These assets

                                        4
<PAGE>   7

include interests in over 4,000 miles of gathering pipelines, which collect gas
from over 3,900 wells. In both 2000 and 1999, we gathered approximately 0.9
Bcf/d of gas and approximately 1 Bcf/d of gas in 1998. We also have an ownership
interest in 16 gas processing and fractionation plants, 12 of which we operate.
Our processing plant capacity is approximately 3.5 Bcf/d. Fractionation capacity
is approximately 106,000 Bbls/d. We also own or have interests in over 600 miles
of natural gas liquids pipelines, and we operate a natural gas liquids storage
facility with a capacity of 2.4 million barrels. Natural gas liquids produced at
our operated plants and from gas processed by others for us averaged more than
60,000 Bbls/d in 2000, as compared to more than 25,000 Bbls/d in 1999 and 23,000
Bbls/d in 1998.

     We hold a 14.6 percent interest in the 250-mile Dauphin Island Gathering
Partners pipeline system that gathers and transports natural gas from major
producing areas offshore in the eastern Gulf of Mexico. Dauphin Island
transports gas onshore to Louisiana and Mobile Bay, Alabama, where we hold an
interest in a 600 MMcf/d gas processing plant and a 40-megawatt cogeneration
plant. The cogeneration plant provides power and processes heat for the gas
plant. The gas plant and associated cogeneration plant, in which we have a 42.4
percent interest, began operations in April 1999. We also have an indirect
interest of 7 percent in the Tri States natural gas liquids pipeline system. Tri
States, which began operations in April 1999, is a 210-mile system that
transports natural gas liquids from the Mobile Bay area gas processing plants to
fractionators and markets in Louisiana.

     In December 2000, the Aux Sable gas processing and fractionation facilities
commenced operations. We own a 14.4 percent interest in the Aux Sable gas
processing and fractionation complex, which is located near Chicago at the
terminus of the Alliance Pipeline system. Aux Sable has exclusive rights to
process natural gas and extract natural gas liquids transported on the Alliance
Pipeline system. The Aux Sable facilities are designed to process up to 2.1
Bcf/d of natural gas and recover approximately 94,000 Bbls/d of natural gas
liquids.

     In January 2000, we placed into service a 150 MMcf/d gas treatment plant in
La Vaca County, Texas, which removes carbon dioxide from the gas produced by us
from the Dry Hollow and Brushy Creek Fields. Also in January 2000, we completed
construction of the Rawhide Buttes gathering system located in the Powder River
Basin of Wyoming. The Rawhide Buttes system gathers gas from coal-bed methane
wells and delivers the gas to an interstate pipeline in Campbell County,
Wyoming.

     CIG provides gathering and processing services on an unbundled or
stand-alone basis. CIG's processing terms are not regulated by FERC, but CIG is
required to provide open access to its processing facilities. CIG's natural gas
gathering and processing facilities are located throughout the production areas
adjacent to its transmission system, with most of its gathering facilities
connected directly to its transmission system. CIG's gathering facilities,
excluding facilities in the Panhandle Field that are used to provide gathering
services regulated by FERC, consist of approximately 2,400 miles of gathering
lines. CIG owned and operated four natural gas processing plants in 2000. These
plants, with a total operating capacity of approximately 477 MMcf/d, recover
mainly propane, butanes, natural gasoline, sulfur and other by-products, which
are sold to refineries, chemical plants and other customers. CIG's gas
processing plants recovered approximately 31 million gallons of liquid
hydrocarbons in 2000, compared to 38 million gallons in 1999 and 46 million
gallons in 1998. Additionally, CIG processed approximately 36 million gallons of
liquid hydrocarbons owned by others in 2000, compared to 24 million gallons in
1999 and 25 million gallons in 1998.

     Our unregulated natural gas and power marketing and trading activities in
North America are conducted through Coastal Merchant Energy, who provides
wholesale energy services to natural gas and power clients and marketing
services to each of our business segments. Prior to October 2000, we conducted
our marketing and trading activities through Engage Energy US, L.P. and Engage
Canada, L.P., a joint venture between us and Westcoast Energy Inc., a major
Canadian natural gas company. During the fourth quarter 2000, we

                                        5
<PAGE>   8

terminated the Engage joint venture and Engage US became Coastal Merchant
Energy, a wholly owned subsidiary of Coastal. Upon the completion of our merger
with El Paso in January 2001, Coastal Merchant Energy was merged into the
merchant operations of El Paso. For the years ended December 31, 2000 and 1999,
Engage US and Coastal Merchant Energy, on a combined basis, had physical sales
volumes of natural gas averaging 3.3 Bcf/d and 3.1 Bcf/d, and combined power
sales were approximately 10 million megawatt hours for both of the years ended
December 31, 2000 and 1999.

     Our international natural gas operations consist of a 113-mile natural gas
pipeline in Victoria, Australia.

                       REFINING, MARKETING AND CHEMICALS

     We are involved in the operation of refineries and chemical plants; the
purchase, transportation and sale of refined products, crude oil, condensate and
natural gas liquids; the sale at retail of gasoline, petroleum products and
convenience items; petroleum product terminaling and the marketing of crude oil
and refined products worldwide.

REFINING

     Our subsidiaries operated their refineries at 93 percent of average
combined capacity in each of 2000 and 1999 compared to 85 percent in 1998. The
aggregate sales volumes (millions of barrels) of our wholly owned refineries
were 181.9 in 2000, 171.3 in 1999 and 154.4 in 1998. Of the total refinery sales
in 2000, 27 percent was gasoline, 50 percent was middle distillates, like jet
fuel, diesel fuel and home heating oil, and 23 percent was heavy industrial
fuels and other products.

     The following table presents average daily throughput and daily capacity
and storage capacity at December 31, 2000 at our wholly owned refineries:

<TABLE>
<CAPTION>
                                                         AVERAGE DAILY     AT DECEMBER 31, 2000
                                                          THROUGHPUT       ---------------------
                                                       -----------------    DAILY      STORAGE
REFINERY                       LOCATION                 2000      1999     CAPACITY    CAPACITY
--------                       --------                -------   -------   --------   ----------
                                                                       (IN BBLS)
<S>                <C>                                 <C>       <C>       <C>        <C>
Aruba              Aruba............................   229,000   195,000   280,000    15,300,000
Corpus Christi     Corpus Christi, Texas............    99,000   100,000   100,000     7,100,000
Eagle Point        Westville, New Jersey............   143,000   143,000   140,000     9,300,000
Mobile             Mobile, Alabama..................    12,000    13,000    18,000       600,000
                                                       -------   -------   -------    ----------
          Total.....................................   483,000   451,000   538,000    32,300,000
                                                       =======   =======   =======    ==========
</TABLE>

     Our refineries produce a full range of petroleum products ranging from
transportation fuels to paving asphalt. They are operated to produce the
particular products required by customers within each refinery's geographic
area. In 2000, the products emphasized included premium gasolines and products
for specialty markets like petrochemical feedstocks, aviation fuels and asphalt.

     On July 30, 1998, we entered into an agreement with a subsidiary of
Petroleos Mexicanos, Mexico's national oil company, for the supply of up to
100,000 Bbls/d of crude oil to support an upgrade of our Aruba refinery. The
upgrade included the installation of a new 30,000 Bbls/d delayed coking unit and
other modifications aimed at increasing the refinery's heavy crude refining and
conversion capacity to approximately 280,000 Bbls/d. The upgrade was completed
in April 2000.

                                        6
<PAGE>   9

MARKETING

     Refined Products Marketing.  The following table presents sales volumes for
distribution activities of our subsidiaries, including products from our
refineries and purchases from other suppliers, for each of the three years ended
December 31, 2000.

<TABLE>
<CAPTION>
TYPE OF SALE                                               2000      1999      1998
------------                                              -------   -------   -------
                                                            (THOUSANDS OF BARRELS)
<S>                                                       <C>       <C>       <C>
Company produced refined products.......................  181,890   171,310   154,427
Refined products purchased from others..................  121,565   104,733   131,508
Natural gas liquids.....................................   12,169    10,629    14,292
                                                          -------   -------   -------
          Total.........................................  315,624   286,672   300,227
                                                          =======   =======   =======
</TABLE>

     Our subsidiaries are wholesale marketers of refined products and liquefied
petroleum gas in 26 states plus Canada, the Dominican Republic, El Salvador, the
Bahamas and Panama through 174 terminals. Coastal Refining & Marketing, Inc.
serves customers primarily in the Midwest, Mississippi Valley and the Southwest
through 94 product and liquefied petroleum gas terminals in 15 states. On the
Gulf and East Coasts, we serve home, industry, utility, defense and marine
energy needs. In 2000, these divisions' sales volumes were 62.7 million barrels,
which accounted for approximately 20 percent of the total marketing and
distribution sales. International subsidiaries that acquire feedstocks for the
refineries and products for the distribution system are located in Aruba, London
and Singapore.

     We lease petroleum storage facilities located at the former U.S. naval base
at Subic Bay in the Philippines. We are leasing 304 acres of land, with 68
individual storage tanks totaling 2.4 million barrels of storage, most of which
are underground, and 40 miles of pipeline connecting the terminal with other
facilities within the Subic Bay Freeport Zone. A joint venture between our
subsidiary and the Petroleum Authority of Thailand rehabilitated the petroleum
products pipeline between the Subic Bay Freeport Zone and the Clark Special
Economic Zone, formerly Clark Air Force Base, along with a petroleum storage
facility in the Clark Special Economic Zone. Both facilities are used to support
the joint venture's marketing activities in the Philippines.

     We have a 50 percent interest in a terminal and port facility near Tallinn,
Estonia on the Baltic Sea. The terminal operation handled imports and exports of
approximately 35.1 million barrels of petroleum products in 2000, primarily from
Russia and the former republics of the Soviet Union to markets in Europe, North
and South America and the Caribbean.

     Through Coastal Mart, Inc. and branded marketers, we conduct retail
marketing, using the C-MART(R), C and Design and/or COASTAL(R) trademarks, in 34
states and Aruba through 1,529 Coastal branded outlets, of which we operate 374
outlets. Fleet fueling operations include 23 outlets in Texas and six in
Florida. In December 2000, we entered into agreements to sell approximately 100
company-operated outlets in New Jersey, Pennsylvania, Virginia, West Virginia,
Tennessee, North Carolina and South Carolina and approximately 100
company-operated outlets in Colorado, Iowa, Kansas, Nebraska, Oklahoma, South
Dakota and Wyoming. The sale of the outlets in the northeastern and eastern
states was completed in February 2001, and the sale of the outlets in the
Midwest is expected to be completed in the second quarter 2001. The agreements
also include the sale of branded marketer and contract dealer accounts covering
355 locations in 19 states. After completion of the proposed sales, the
Company's retail marketing operations will be conducted in 23 states and Aruba
through 973 Coastal-branded outlets, of which 176 will be company operated.

     Through Coastal Unilube, Inc., we blend, package and distribute lubricants
and automotive products under the COASTAL(R), C and Design and other trademarks
through 8 warehouses servicing customers in 44 states, plus the District of
Columbia, Puerto Rico, the U.S. Virgin Islands and 28 foreign countries.

     To support our refining and marketing operations, we have transportation
facilities including petroleum liquids pipelines, tank cars, tankers, tank
trucks and barges. We operate almost 1,900 miles of pipeline for gathering and
transporting an average of 251,626 Bbls/d of crude oil, condensate, natural gas
liquids and refined products. These pipelines include 304 miles of crude oil
pipelines, 848 miles of refined products
                                        7
<PAGE>   10

pipelines, and 582 miles of natural gas liquids pipelines, located mainly in
Texas and in which we have approximately a 28 percent ownership interest. We
have a 50 percent ownership in 13 miles of refined products pipelines located in
New Jersey and New York. We also have a 33.3 percent interest in 80 miles of
refined products pipelines in New Jersey and 28 miles of crude pipelines in
Louisiana. We also have 26-mile crude pipeline located in Utah and Wyoming. In
2000, throughput of crude oil pipelines averaged 31,798 Bbls/d, compared to
38,877 Bbls/d in 1999 and 15,323 Bbls/d in 1998. In 2000, throughput of refined
products and natural gas liquid pipelines averaged 219,828 Bbls/d, compared to
210,529 Bbls/d in 1999 and 207,800 Bbls/d in 1998.

     Our marine transportation fleet at December 31, 2000 consisted of 15 tug
boats, 19 oil barges, 3 owned tankers and 11 time-chartered tankers.

CHEMICALS

     Our chemical production facilities, located in Cheyenne, Wyoming; Battle
Mountain, Nevada; and St. Helens, Oregon, produce a variety of nitrogen-based
chemicals and oxygenates that are marketed to serve agricultural and industrial
markets throughout the western United States.

     Coastal Chem, Inc. operates a plant near Cheyenne, Wyoming, which produces
anhydrous ammonia, ammonium nitrate, nitric acid, liquid carbon dioxide,
methanol and urea for use as agricultural fertilizers, livestock feed
supplements, blasting agents and various other industrial applications. Our
Cheyenne, Wyoming plant has the capacity to produce 550 tons per day of
anhydrous ammonia, 875 tons per day of ammonium nitrate, 700 tons per day of
nitric acid, 400 tons per day of liquid carbon dioxide, 225 tons per day of
methanol, and 320 tons per day of urea, Coastal Chem also owns a plant at Table
Rock, Wyoming, which has a production capacity of 150 tons of liquid fertilizer
per day. In addition, Coastal Chem operates a low density ammonium nitrate
(LoDAN(R)) facility in Battle Mountain, Nevada, which has the capacity to
produce 440 tons per day of LoDAN(R) and 350 tons of nitric acid per day. The
LoDAN(R) product is used primarily as a blasting agent in surface mining.

     Coastal Chem also operates an integrated methyl tertiary butyl ether (MTBE)
plant in Cheyenne, Wyoming, with a production capacity of 4,300 barrels per day.
MTBE is a gasoline additive which adds oxygen and boosts octane of the blended
mixture.

     Our St. Helens chemical plant, located in St. Helens, Oregon, has the
capacity to produce 300 tons per day of anhydrous ammonia, 400 tons per day of
urea and 85 tons per day of ammonium nitrate solutions.

     Sales volumes for Coastal Chem and St. Helens for the three years ended
December 31, 2000, are set forth below (thousands of tons):

<TABLE>
<CAPTION>
                                                              2000    1999    1998
                                                              -----   -----   -----
<S>                                                           <C>     <C>     <C>
Agricultural Sales..........................................    389     326     346
Industrial Sales............................................    547     608     550
MTBE........................................................    214     209     210
                                                              -----   -----   -----
          Total.............................................  1,150   1,143   1,106
                                                              =====   =====   =====
</TABLE>

     Coastal Chem and the St. Helens plant compete with many nitrogen and MTBE
producers across the U.S. and Canada. Their strengths are product quality,
service, and dependability. Coastal Chem and the St. Helens plant produce
commodity products with strong price competition from producers worldwide.

     In November 1998, we suspended operations at our petrochemical facility in
Montreal East, Quebec, Canada. Operations will be resumed when supply/demand
conditions provide the necessary economic support. The petrochemical facility
has the capacity to produce 330,000 tons per year of paraxylene, a component
used in the manufacturing of polyester fibers and containers. In September 2000,
we reduced our 100 percent ownership interest in the petrochemical facility to
51 percent.

                                        8
<PAGE>   11

     Our 660-tons-per-day anhydrous ammonia facility located at Oyster Creek in
Freeport, Texas began operation in the first quarter of 1998. Production (in
tons) sold from the facility for the year ended December 31, 2000, was 131,200
as compared to 137,800 in 1999 and 45,000 in 1998. This plant is located
adjacent to and supplies a number of major chemical facilities.

COMPETITION

     The petroleum industry is highly competitive in the United States and
throughout most of the world. Our refining and marketing of petroleum products
and chemicals businesses compete with other industries in supplying the energy
needs of various types of consumers. Principal factors affecting sales are
price, location and service. Overall performance is impacted by industry margins
and supply and demand for both feedstocks and finished products.

                           EXPLORATION AND PRODUCTION

GAS AND OIL PROPERTIES

     We are engaged in gas and oil exploration, development and production
operations in Colorado, Kansas, Louisiana, New Mexico, Oklahoma, Texas, Utah,
Wyoming and offshore in the Gulf of Mexico. In addition, we have exploration and
production rights in Australia, Brazil, Canada, Hungary and Indonesia.

     In 2000, our domestic exploration and production operations sold
approximately 24 percent of all the gas produced to our wholly owned natural gas
system subsidiaries and approximately 67 percent to Engage prior to the
dissolution of the Engage joint venture in the fourth quarter 2000. Our domestic
operations also make short-term gas sales directly to industrial users and
distribution companies. Oil is sold primarily under short-term contracts at
field prices posted by the principal purchasers of oil in the areas in which the
producing properties are located.

     The following table details our gross and net acreage held under gas and
oil mineral leases at December 31, 2000.

<TABLE>
<CAPTION>
                                              UNDEVELOPED       DEVELOPED         TOTAL
                                             --------------   -------------   --------------
AREA                                         GROSS     NET    GROSS    NET    GROSS     NET
----                                         ------   -----   -----   -----   ------   -----
                                                          (THOUSANDS OF ACRES)
<S>                                          <C>      <C>     <C>     <C>     <C>      <C>
Exploration and Production
  United States (Domestic)
     Onshore...............................   1,452   1,016   1,320     527    2,772   1,543
     Offshore..............................     533     456     418     275      951     731
                                             ------   -----   -----   -----   ------   -----
          Total Domestic...................   1,985   1,472   1,738     802    3,723   2,274
                                             ------   -----   -----   -----   ------   -----
  Canada...................................     246     182      11       9      257     191
                                             ------   -----   -----   -----   ------   -----
          Total North America..............   2,231   1,654   1,749     811    3,980   2,465
                                             ------   -----   -----   -----   ------   -----
  International
     Australia.............................   1,770     614      --      --    1,770     614
     Brazil................................   4,246   3,321      --      --    4,246   3,321
     Hungary...............................     568     568      --      --      568     568
     Indonesia.............................   1,374     442      --      --    1,374     442
                                             ------   -----   -----   -----   ------   -----
          Total International..............   7,958   4,945      --      --    7,958   4,945
                                             ------   -----   -----   -----   ------   -----
          Total Exploration and
            Production.....................  10,189   6,599   1,749     811   11,938   7,410
                                             ------   -----   -----   -----   ------   -----
Natural Gas Systems(1)
  Domestic Onshore.........................      --      --     263     259      263     259
                                             ------   -----   -----   -----   ------   -----
          Total Acreage....................  10,189   6,599   2,012   1,070   12,201   7,669
                                             ======   =====   =====   =====   ======   =====
</TABLE>

---------------
(1) These are reserves owned by CIG.

                                        9
<PAGE>   12

     The domestic net developed acreage is concentrated principally in Texas (32
percent), Utah (30 percent), offshore Gulf of Mexico (26 percent), Colorado (9
percent) and Oklahoma (2 percent). Approximately 15 percent, 9 percent and 26
percent of our total domestic net undeveloped acreage is under leases that have
minimum remaining primary terms expiring in 2001, 2002 and 2003, respectively.

     The following table details our domestic productive wells at December 31,
2000. Gross wells include 58 multiple completions.

<TABLE>
<CAPTION>
TYPE OF WELL                                                  GROSS    NET
------------                                                  -----   -----
<S>                                                           <C>     <C>
Exploration and Production
  Oil.......................................................    468     329
  Gas.......................................................  3,042   2,242
                                                              -----   -----
          Total Exploration and Production..................  3,510   2,571
                                                              -----   -----
Natural Gas Systems
  Oil.......................................................      9       8
  Gas.......................................................    809     789
                                                              -----   -----
          Total Natural Gas Systems.........................    818     797
                                                              -----   -----
          Total.............................................  4,328   3,368
                                                              =====   =====
</TABLE>

EXPLORATION AND DRILLING

     During 2000, we participated in drilling 332 domestic gross wells, 256.5
net wells, to our interest. The following table details our participation in
wells drilled during the years 1998 through 2000.

<TABLE>
<CAPTION>
                                                   2000          1999          1998
                                                -----------   -----------   -----------
                                                GROSS   NET   GROSS   NET   GROSS   NET
                                                -----   ---   -----   ---   -----   ---
<S>                                             <C>     <C>   <C>     <C>   <C>     <C>
Exploration and Production
  Exploratory Wells
     Oil......................................    --     --     --     --     --     --
     Gas......................................    11     10      9      7      7      5
     Dry Holes................................     8      7      5      5      7      3
                                                 ---    ---    ---    ---    ---    ---
                                                  19     17     14     12     14      8
                                                 ---    ---    ---    ---    ---    ---
  Development Wells
     Oil......................................     3      1      1      1      4      3
     Gas......................................   289    223    238    180    186    140
     Dry Holes................................    14     14      1      1      2      1
                                                 ---    ---    ---    ---    ---    ---
                                                 306    238    240    182    192    144
                                                 ---    ---    ---    ---    ---    ---
Natural Gas Systems
  Development Wells
     Oil......................................    --     --     --     --     --     --
     Gas......................................     7      1     22     13      6      6
     Dry Holes................................    --     --     --     --     --     --
                                                 ---    ---    ---    ---    ---    ---
                                                   7      1     22     13      6      6
                                                 ---    ---    ---    ---    ---    ---
          Total...............................   332    256    276    207    212    158
                                                 ===    ===    ===    ===    ===    ===
</TABLE>

                                        10
<PAGE>   13

     The following table details domestic wells in progress as of December 31,
2000.

<TABLE>
<CAPTION>
TYPE OF WELL                                                  GROSS   NET
------------                                                  -----   ---
<S>                                                           <C>     <C>
Exploration and Production
  Exploratory...............................................   13     13
  Development...............................................   50     39
                                                               --     --
          Total Exploration and Production..................   63     52
                                                               ==     ==
</TABLE>

     There were no exploratory or development wells in progress for the natural
gas systems segment as of December 31, 2000.

     Our domestic exploration and development operations are focused on three
core areas: the Texas Coastal Plain, the Gulf of Mexico and the Rocky Mountains.

     In 2000, the Texas Coastal Plain continued its significant contribution
with net average natural gas production of approximately 460 MMcf/d compared
with 329 MMcf/d in 1999. Proved reserve inventory for the area at the end of
2000 amounted to 1,765 Bcfe compared to the year end 1999 level of 1,255 Bcfe.
Activities on the Texas Coastal Plain focused on two major production trends,
the Wilcox trend and the Frio/Vicksburg trend.

     At the end of 2000, we held interests in 188 blocks and 89 platforms in the
Gulf of Mexico. Net annual average natural gas production increased to 315
MMcf/d in 2000 compared to 193 MMcf/d in 1999. We operate 73 of the platforms as
compared with 63 at the end of 1999. Proved reserve inventory for the Gulf of
Mexico at the end of 2000 was 813 Bcfe compared to 804 Bcfe at the end of 1999.

     In 2000, the Rocky Mountain region increased its contribution with net
average natural gas production of approximately 106 MMcf/d compared with 93
MMcf/d in 1999. Proved reserve equivalent inventory for the area at the end of
2000 was 1,731 Bcf compared to 1,455 Bcf in 1999. Activities in the region focus
on three major production basins, Uinta, Piceance, and Douglas Arch.

     In Canada, we are continuing to develop and acquire production to support
our shipping commitment on the Alliance Pipeline. At year end 2000, we held
interests in 257,554 gross acres (191,188 net acres), had completed 21.2
successful net gas wells and have about 190 Bcf equivalent of proved reserve
inventory. Capital expenditures for Canadian development in 2000 were
approximately $120 million.

     Also, at the end of 2000, we held interests in 4,245,495 gross acres
(3,320,744 net acres) and had about 120 Bcfe of proved undeveloped reserves in
Brazil. Capital expenditures in Brazil for 2000 were $11 million.

GAS AND OIL PRODUCTION

     Natural gas production from domestic properties during 2000 averaged 988
MMcf/d, compared to 729 MMcf/d in 1999. Production from non-pipeline owned wells
averaged 896 MMcf/d in 2000, compared to 632 MMcf/d in 1999. Crude oil,
condensate and natural gas liquids production from domestic properties averaged
17,764 Bbls/d in 2000, compared to 12,326 Bbls/d in 1999.

                                        11
<PAGE>   14

     The following table presents gas, oil, condensate and natural gas liquids
production volumes of our domestic interest in gas and oil properties for the
three years ended December 31, 2000:

<TABLE>
<CAPTION>
                                                                               NATURAL GAS
YEAR                                           GAS       OIL     CONDENSATE      LIQUIDS
----                                         -------   -------   -----------   -----------
                                                                 (THOUSANDS
                                             (MMCF)    (MBBLS)   OF BARRELS)     (MBBLS)
<S>                                          <C>       <C>       <C>           <C>
Exploration and Production
  2000.....................................  328,007    2,746       2,694         1,037
  1999.....................................  230,542    2,190       1,713           572
  1998.....................................  185,732    3,725       1,633           220
Natural Gas Systems
  2000.....................................   33,433       25          --            --
  1999.....................................   35,634       24          --            --
  1998.....................................   39,058       44          --            --
</TABLE>

     Many of our domestic gas wells are situated in areas near, and are
connected to, our gas systems. In other areas, gas production is sold to
pipeline companies and other purchasers.

     Generally, our domestic production of crude oil, condensate and natural gas
liquids is purchased at the wellhead by our marketing and refining affiliates.
Some quantities are delivered via our gathering and transportation lines to our
refineries, but most quantities are redelivered to us through various exchange
agreements.

     The following table summarizes sales price and production cost information
for domestic exploration and production operations during the years ended
December 31:

<TABLE>
<CAPTION>
                                                              2000     1999     1998
                                                             ------   ------   ------
<S>                                                          <C>      <C>      <C>
Average Realized Sales Price

  Natural Gas ($/Mcf)......................................  $ 2.81   $ 2.17   $ 2.02
  Oil ($/Bbl)..............................................   19.97    12.14    12.80
  Condensate ($/Bbl).......................................   28.14    16.30    11.08
  Natural Gas Liquids ($/Bbl)..............................   29.29    18.00    15.24
Average Production Cost ($/Mcfe)...........................    0.45     0.40     0.41
</TABLE>

COMPANY-OWNED RESERVES

     Our estimated domestic proved reserves of crude oil, condensate and natural
gas liquids at December 31, 2000, as estimated by us and reviewed by Huddleston,
were 65.0 million barrels, compared to 57.1 million barrels at the end of 1999.
Proved gas reserves as of December 31, 2000, net to our interest, were estimated
by us and reviewed by Huddleston to be 4,196 Bcf compared to 3,467 Bcf as of
December 31, 1999. For the sixth consecutive year, we added proved reserves in
2000 that were more than triple our production volumes.

     For information on owned reserves of oil and gas, see Item 8, Financial
Statements and Supplementary Data, Note 17.

COMPETITION

     In the United States, we compete with major integrated oil companies and
independent oil and gas companies for suitable prospects for oil and gas
drilling operations. The availability of a ready market for gas discovered and
produced depends on numerous factors frequently beyond our control. These
factors include the extent of gas discovery and production by other producers,
crude oil imports, the marketing of competitive fuels, and the proximity,
availability and capacity of gas pipelines and other facilities for the
transportation and marketing of gas. The production and sale of oil and gas is
subject to a variety of federal and state regulations, including regulation of
production levels.

                                        12
<PAGE>   15

REGULATION

     In all states in the United States in which we engage in oil and gas
exploration and production, our activities are subject to regulation.
Regulations may extend to requiring drilling permits, the spacing of wells, the
prevention of waste and pollution, the conservation of natural gas and oil, and
various other matters. Regulations may impose restrictions on the production of
natural gas and crude oil by reducing the rate of flow from individual wells
below their actual capacity to produce. Likewise, oil and gas operations on all
federal lands are subject to regulation by the U.S. Department of the Interior
and other federal agencies.

                                      COAL

     Through the operations of Coastal Coal Company, LLC and its affiliates in
the eastern United States, we produce and market high quality bituminous coal
from reserves in Kentucky, Virginia and West Virginia. In addition, Coastal Coal
leases interests in its reserves to unaffiliated producers and markets
third-party coal through brokerage sales operations.

     At December 31, 2000, coal properties consisted of the following:

<TABLE>
<CAPTION>
                                                  COAL HOLDINGS (ACRES)
                                     ------------------------------------------------
                                               OWNED               LEASED                 CLEAN,
                                     --------------------------   EXCHANGED    TOTAL    RECOVERABLE
                                      FEE     MINERAL   SURFACE     (NET)      ACRES      TONS(1)
                                     ------   -------   -------   ---------   -------   -----------
                                                                                        (MILLIONS)
<S>                                  <C>      <C>       <C>       <C>         <C>       <C>
Kentucky...........................  14,173    66,093    2,512     32,546     115,324       218
Virginia...........................  24,618    36,593    2,090     16,925      80,226       162
West Virginia......................   1,081    52,293    3,879     43,430     100,683       156
                                     ------   -------    -----     ------     -------       ---
          Total....................  39,872   154,979    8,481     92,901     296,233       536
                                     ======   =======    =====     ======     =======       ===
</TABLE>

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

(1) Based on a 65 percent recovery rate.

     We control approximately 536 million recoverable tons of bituminous coal
reserves and resources. Production in 2000 from Coastal Coal's reserves totaled
11.5 million tons, of which 8.1 million tons were produced from captive
operations and 3.4 million tons were produced by lessees under royalty
agreements. In its captive operations, Coastal Coal has 15 mines in Kentucky,
Virginia and West Virginia, which provide for the majority of its production.
Captive production and clean coal processed from these mines totaled 5.6 million
tons in 2000. The remaining production is derived from contracts with
independent mine operators to deliver coal to our processing and loading
facilities.

     Captive sales by Coastal Coal were 9.8 million tons in 2000, as compared to
9.0 million tons in 1999. Brokerage sales in which we receive a commission
totaled 0.3 million tons for 2000 and 0.5 million tons for 1999.

     In 2000, approximately 83 percent of the captive sales were to domestic
utilities, 10 percent of the sales were to domestic industrial customers and 7
percent of the sales were to export markets in Europe and Canada. Of the total
2000 tonnage sold, 8.8 million tons (90 percent) were sold under long-term
contracts. At December 31, 2000, the weighted average remaining life of these
contracts was 35 months.

     We had approximately 14.1 million tons of annual production capacity at
December 31, 2000 from four coal preparation plants and six loading facilities
we own and operate in the central Appalachian coal fields.

     In addition to our bituminous coal operations, we control overriding
royalty interests in approximately 411 million tons of lignite reserves in North
Dakota. Production from these reserves in 2000 totaled 4.6 million tons.

     Through our captive operations, leasing programs and brokerage activities,
we participate in all aspects of the bituminous coal industry. A significant
portion of our reserves are low-sulfur, compliance coal which will

                                        13
<PAGE>   16

allow us to remain a major supplier of steam coal to domestic utilities under
the Clean Air Act Amendments of 1990.

COMPETITION

     We compete with a large number of coal producers and land holding companies
in the eastern United States. The factors affecting our coal sales are price,
quality (BTU, sulfur and ash content), royalty rates, employee productivity and
rail freight rates.

                                     POWER

DOMESTIC

     Coastal Power Company and its affiliates develop, operate and own various
equity interests in cogeneration and independent power projects. The projects
produce and sell electrical energy, and in the case of cogeneration projects,
they sell thermal energy as well. Affiliates of Coastal Power have interests in
six operating domestic cogeneration projects and 12 foreign operating
independent power projects, as well as interests in other projects in various
stages of construction and development.

     Capitol District Cogeneration -- We own a 50 percent equity interest in
Capitol District Energy Center Cogeneration Associates, the owner of a combined
cycle cogeneration facility in Hartford, Connecticut with a capacity of
approximately 56 megawatts, and we also operate and manage the plant.
Electricity from the facility is sold to a local utility under a long-term
contract. Gas supply is provided to the cogeneration plant by some of our other
affiliates. Thermal energy from the plant is sold to a local heating and cooling
supplier in the city of Hartford.

     Midland Cogen -- We hold an approximate 44 percent equity interest in the
Midland Cogeneration Venture Limited Partnership, a 1,500-megawatt, gas-fired
cogeneration project in Michigan, which is the largest cogeneration facility in
the United States. Power from the project is sold to a local utility and the
project's thermal host under long-term contracts. Steam from the project is also
sold to the thermal host and its affiliate under long-term contracts. Our
affiliates provide gas supply and transportation services for a portion of the
project's fuel requirements.

     Eagle Point -- We operate and have a 50 percent ownership interest in a
combined-cycle cogeneration plant at our Eagle Point, New Jersey refinery. The
plant has a capacity of approximately 225 megawatts. Power from the plant is
sold to a local utility and our refinery under long-term contracts. Steam from
the plant is also sold to the refinery under a long-term contract. Gas supply
and transportation, as well as liquid fuel, is provided to the cogeneration
plant by some of our other affiliates. Effective as of January 1, 2001, we
acquired an additional 34 percent interest in the facility.

     Fulton -- We own 100 percent of Fulton Cogeneration Associates, L.P., a New
York limited partnership. Fulton owns one Colorado and two New York operating
power projects.

     The Fulton, New York plant is a leased cogeneration facility with a
capacity of approximately 47 megawatts. Electricity from this project is sold to
a New York utility/system operator under a long-term contract and to an
affiliate of Fulton that resells into the wholesale market. Thermal energy is
sold to a confection manufacturer adjacent to the project, also under a
long-term contract.

     Rensselaer -- The 79.6-megawatt, combined-cycle Rensselaer cogeneration
facility near Albany, New York was acquired by Fulton in March 1999. The
facility is natural gas-fired, but is capable of utilizing No. 2 fuel oil.
Electricity from the facility is sold primarily to a New York utility/system
operator under a long-term contract.

     ManChief -- ManChief, Fulton's Colorado power project, commenced
construction in 1999, and the plant went into full commercial operation in July
2000. Located near Denver, Colorado, ManChief is a 265-megawatt facility that
sells a substantial portion of its capacity to a Colorado utility under a
long-term contract.

                                        14
<PAGE>   17

INTERNATIONAL

  Latin America

     Compania de Electricidad -- We own a 48.3 percent equity interest in
Compania de Electricidad de Puerto Plata, S.A., which owns an independent power
project in Puerto Plata, Dominican Republic. The project has a total capacity of
66.5 megawatts, of which 50 megawatts are barge mounted and 16.5 megawatts are
land based. An affiliate of Coastal Power is involved in arranging the fuel for
the project, and another affiliate operates the project. The electrical energy
is sold to the national electric utility of the Dominican Republic under a
long-term contract.

     Nejapa -- Coastal Nejapa Ltd. and other affiliates lease an independent
power project near Apopa, El Salvador. The heavy fuel oil-fired plant has a
capacity of approximately 144 megawatts. Coastal Power, through its affiliates,
currently receives approximately 86.6 percent of the distributable cash flow and
a third party receives the remainder. Our affiliates provide fuel for this
project, and another of our affiliates operates the project pursuant to a
long-term contract. The electrical energy is sold to the national electric
utility of El Salvador under a long-term contract.

     Tipitapa -- Our subsidiary owns a 60 percent equity interest in the
51-megawatt (net) heavy fuel oil-fired project in Tipitapa, Nicaragua, with
Nicaraguan partners owning the remaining 40 percent interest. Operations
commenced in the first quarter of 1999, and the power from the project is sold
to the national utility company under a long-term contract. An affiliate of
Coastal Power operates the project pursuant to a long-term contract.

     Fortuna -- In January 1999, a consortium comprised of a subsidiary of
Coastal Power and Hydro-Quebec International Inc. purchased a 49 percent
interest in Empresa de Generation Electrica Fortuna, S.A., with the Coastal
Power subsidiary holding approximately 49.9 percent of the acquired interest in
Fortuna. Fortuna owns and operates a 300-megawatt hydroelectric plant located on
the Chiriqui River in the highlands region of Panama's Chiriqui province. The
plant began operating in 1983.

     Itabo -- In September 1999, a subsidiary of Coastal Power acquired a 49.99
percent interest in Class B shares of the Itabo Generation Company, with the
Class B shares representing a 50 percent interest in Itabo. Itabo owns and
operates several electric generating facilities in southern Dominican Republic,
aggregating over 580 megawatts of nominal generating capacity.

  Asia

     Wuxi -- Coastal Wuxi Power Ltd., an affiliate of Coastal Power, together
with two Chinese partners, formed a Sino-foreign joint venture company to own,
construct, and operate a simple-cycle, diesel-fired peaking plant. The project
has a capacity of approximately 40 megawatts and is located in Wuxi City,
Province of Jiangsu, The People's Republic of China. Coastal Wuxi owns a 60
percent equity interest in the joint venture. Power generated by the plant is
sold to the local utility under a long-term contract.

     Suzhou -- Coastal Suzhou Power Ltd., a subsidiary of Coastal Power,
together with a Chinese partner, formed a Sino-foreign joint venture to develop,
construct, own and operate an independent power project. The project has a
capacity of approximately 76 megawatts and is located in Suzhou City, Province
of Jiangsu, The People's Republic of China. Coastal Suzhou owns a 60 percent
equity interest in the joint venture. Power generated by the plant is sold to
the local utility under a long-term contract.

     Gusu -- Coastal Gusu Heat & Power Ltd., an affiliate of Coastal Power,
together with a Chinese partner, formed a Sino-foreign joint venture to develop,
construct, own and operate a 24-megawatt cogeneration plant adjacent to our
existing Suzhou City plant. Coastal Gusu owns a 60 percent equity interest in
the joint venture. Power generated by the plant is sold to the local utility
under a long-term contract.

     Nanjing -- Also operating in Jiangsu Province, The People's Republic of
China, Coastal Nanjing Power Ltd., a subsidiary of Coastal Power, together with
two Chinese partners, formed a Sino-foreign joint venture to develop, construct,
own and operate an independent power project. The project has a capacity of

                                        15
<PAGE>   18

approximately 72 megawatts and is located in Nanjing City. Coastal Nanjing owns
an 80 percent equity interest in the joint venture. The power is sold to the
local utility under a long-term contract.

     Khulna -- In southwestern Bangladesh, Coastal Power Khulna Ltd., a
subsidiary of Coastal Power, acquired an interest in a 110-megawatt, fuel
oil-fired, barge-mounted power plant located in Khulna. Our subsidiary's
interest is 66.7 percent, net of an outstanding commitment to sell approximately
7 percent at par to an unrelated party. The power generated by the project is
being sold to the national utility under a long-term contract. An affiliate of
Coastal Power is a consortium member of the project fuel supplier.

     Quetta -- A subsidiary of Coastal Power is currently entitled to
approximately 90 percent of the profits and cash flows of a 140-megawatt,
natural gas-fired power plant in Quetta, Pakistan, with an unrelated entity
entitled to the remaining 10 percent. Commercial operations began in September
1999. The power from the project is sold to a national utility under a long-term
contract.

     Saba -- A subsidiary of Coastal Power has a financial stake of
approximately 93 percent in a 125-megawatt, heavy fuel oil project in
Farouqabad, Pakistan. Commercial operations began in December 1999, and the
power from the project is sold to a national utility under a long-term contract.
An affiliate of Coastal Power operates the facility.

COMPETITION

     Coastal Power and its affiliates are subject to competition with other
energy organizations and utilities seeking to develop and acquire independent
power operations. We and many other power producers are concentrating our
efforts in the United States and abroad. Competition continues to increase as
the world market for independent power production develops and power purchasers
employ competitive bidding for project awards. In the U.S. and international
locations, the sale of power and the operation of power cogeneration facilities
are regulated by the applicable laws, rules and regulations of the respective
governments and agencies having jurisdiction. Many states in the U.S. are
restructuring their applicable laws, rules and regulations. This restructuring
is likely to result in new development opportunities in the United States and
increased competition in response to such opportunities.

                                  COMPETITION

     We are subject to competition. In all our business segments, competition is
based primarily on price with factors such as reliability of supply, service and
quality being considered. Our natural gas systems; refining, marketing and
chemicals; exploration and production; coal and power subsidiaries are engaged
in highly competitive businesses against competitors, some of which have larger
facilities and market share. See also the discussion of competition under
"Natural Gas Systems," "Refining, Marketing and Chemicals," "Exploration and
Production," "Coal" and "Power".

                                 ENVIRONMENTAL

     A description of our environmental activities is included in Item 8,
Financial Statements and Supplementary Data, Note 15, and is incorporated by
reference herein.

                                   EMPLOYEES

     At January 31, 2001, we had approximately 10,220 employees, of which
approximately 600 are subject to collective bargaining agreements.

                                        16
<PAGE>   19

ITEM 2. PROPERTIES

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

     We are of the opinion that 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 such property or the interests therein 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.

ITEM 3. LEGAL PROCEEDINGS

     See Item 8, Financial Statements and Supplementary Data, Note 15, which 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.

                                        17
<PAGE>   20

                                    PART II

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

     On January 29, 2001, a wholly owned subsidiary of El Paso was merged with
us. As a result of the merger and the conversion of all of our outstanding
common stock and Class A common stock into El Paso common stock, all of our
common stock is owned by El Paso.

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.

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.

     In January 2001, we became a wholly owned subsidiary of El Paso through our
merger with a wholly owned El Paso subsidiary. In the merger, each share of our
common stock and Class A common stock was converted on a tax-free basis into
1.23 shares of El Paso common stock. Our outstanding convertible preferred stock
was exchanged on a tax-free basis for El Paso common stock on the same basis as
if the preferred stock had been converted into our common stock immediately
prior to the merger. El Paso issued a total of approximately 271 million shares
of its common stock, including approximately 4 million shares issued in exchange
for our outstanding stock options. The shares issued in exchange for our stock
options were issued based on the fair value of these options on the merger date.
These exchanges will result in a charge of approximately $278 million that we
will record in the first quarter of 2001.

     In September 2000, we announced that our pipeline operations would be
combined with El Paso's following the merger. In the consolidation, ANR's
headquarter operations will be relocated from Detroit, Michigan to Houston,
Texas, and El Paso's operations in El Paso, Texas will be relocated to Colorado
Springs, Colorado. We expect to incur charges associated with relocations of
employees and assets, and charges for asset and contract terminations that will
occur as operations are consolidated. We anticipate a majority of these charges
will occur in the first quarter of 2001.

     On January 30, 2001, we completed an employee restructuring, that resulted
in the reduction of approximately 3,200 full time positions through a
combination of early retirements and terminations. These reductions occurred
across all of our locations and business segments. These actions will result in
severance and termination charges, retention payments to employees retained on a
transition basis following the merger, and the acceleration of employee benefit
payments under existing benefit plans and employment contracts. We expect a
majority of these charges to occur in the first quarter of 2001.

     Pursuant to the El Paso merger, we have been ordered by the Federal Trade
Commission to sell several assets. Assets we have been, or will be, required to
sell include our Gulfstream system, our interests in the Stingray and U-T
Offshore systems, and our interests in the Empire pipeline and Iroquois pipeline
systems. The sales of Gulfstream and our interests in the Stingray and U-T
Offshore systems were completed in February 2001. Proceeds from these sales were
approximately $70 million, resulting in a first quarter 2001 loss from those
sales of approximately $29 million. The sales of our interests in the Empire and
Iroquois systems are also expected to be completed in the first half 2001.

     The final cost of our merger-related activities, and the charges we will
incur as we continue to integrate our activities with El Paso are not fully
known at this time. However, we expect that most of these charges will be
recorded in 2001.

                                        18
<PAGE>   21

                             RESULTS OF OPERATIONS

     Our business activities are segregated into five segments: natural gas;
refining, marketing and chemicals; exploration and production; power and coal.
These segments are strategic business units that offer a variety of different
energy products. Since earnings on equity investments can be a significant
source of earnings in several of our segments, we evaluate segment performance
based on earnings before interest expense, (including minority interest) and
income taxes, or EBIT, instead of operating income.

     The following table presents EBIT by segment and in total for the years
ended December 31, 2000 and 1999:

<TABLE>
<CAPTION>
                                                               2000        1999
                                                              ------      ------
                                                                (IN MILLIONS)
<S>                                                           <C>         <C>
EBIT
Natural gas.................................................  $  660      $  574
Refining, marketing, and chemicals..........................     260         228
Exploration and production..................................     426         186
Power.......................................................     142          89
Coal........................................................       3          16
                                                              ------      ------
  Segment EBIT..............................................   1,491       1,093
                                                              ------      ------
Corporate expenses, net.....................................    (115)        (65)
                                                              ------      ------
  Consolidated EBIT.........................................  $1,376      $1,028
                                                              ======      ======
</TABLE>

NATURAL GAS

     Our Natural Gas operations involve the production, purchase, gathering,
processing, transportation, storage, marketing and sale of natural gas,
principally to utilities, industrial customers and other pipelines, and include
the operations of natural gas liquids extraction plants. The operations involve
both regulated and unregulated companies. The interstate natural gas pipeline
and several of our storage subsidiaries are subject to the regulations and
accounting procedures of FERC.

     In October 2000, we terminated the Engage joint venture formed in 1997 with
Westcoast Energy, Inc. The operations were divided into separate entities that
are owned and operated independently by each company. After the joint venture
termination, our operations were conducted through Coastal Merchant Energy.
Natural gas operating revenues for the last three months of 2000 include
revenues of $1,871 million from Coastal Merchant Energy's operations. Subsequent
to the El Paso merger in January 2001, Coastal Merchant Energy was merged into
and is being operated as part of El Paso Merchant Energy, L.P. Prior to the
termination of the joint venture, Engage's revenues are not included in our
operating revenues; however, our share of Engage's net earnings is included in
Other income, net.

     Natural gas operating results and an analysis of those results for the
years ended December 31, 2000 and 1999 are as follows:

<TABLE>
<CAPTION>
                                                               2000     1999
                                                              ------   ------
                                                               (IN MILLIONS)
<S>                                                           <C>      <C>
Operating revenues..........................................  $3,643   $1,247
Purchases...................................................   2,410      118
Operating expenses..........................................     706      651
Equity income from investments..............................     133       96
EBIT........................................................     660      574
Total throughput volume (Bcf)...............................   2,181    2,109
</TABLE>

     YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999.  The
increase in operating revenues of $2,396 million in 2000 can be primarily
attributed to the operations from Coastal Merchant Energy following its
consolidation as a subsidiary in October 2000; increased volumes of natural gas

                                        19
<PAGE>   22

liquids, primarily as a result of gas processing plants we acquired at the end
of 1999; higher prices for natural gas and natural gas liquids and the favorable
resolution of litigation in 2000.

     Purchases increased by $2,292 million, primarily due to the operations of
Coastal Merchant Energy, higher natural gas prices and increased costs for the
gas processing plants. The Coastal Merchant Energy operations added $1,858
million to the higher purchases. Operating expenses increased in 2000 primarily
as a result of higher expenses for the gas processing plants. The increased
equity income results from investments by our unregulated gas operations and
increased earnings from Engage prior to the termination of the joint venture.
Gross profit increased by $104 million over 1999 as a result of the increased
volumes of and margins for natural gas liquids, gross margin from the
consolidation of Coastal Merchant Energy and the favorable resolution of
litigation in 2000.

     Throughput for our regulated pipeline subsidiaries increased by 3 percent
over 1999, and the net processing throughput for our unregulated natural gas
operations was up about 230 percent from 1999.

REFINING, MARKETING AND CHEMICALS

     Refining, marketing and chemicals operations involve the purchase,
transportation and sale of refined products, crude oil, condensate and natural
gas liquids; the operation of refineries and chemical plants; the sale at retail
of gasoline, petroleum products and convenience items; petroleum product
terminaling and marketing of crude oil and refined products worldwide.

     In 2000, we applied Financial Accounting Standards Board (FASB) Emerging
Issues Task Force Issue No. 99-19, Reporting Revenue Gross as a Principal versus
Net as an Agent, which resulted in the reclassification of revenues and
purchases for various trading and marketing activities that had been previously
reported on a net basis. As a result of the adoption, operating revenues and
purchases increased by $4.0 billion, $2.1 billion and $2.0 billion in 2000, 1999
and 1998. This change had no impact on gross margins or net income. Prior years
amounts have been reclassified to conform with the new presentation.

     Operating results for refining, marketing and chemicals and an analysis of
those results for the years ended December 31, 2000 and 1999 are as follows:

<TABLE>
<CAPTION>
                                                               2000      1999
                                                              -------   ------
                                                               (IN MILLIONS)
<S>                                                           <C>       <C>
Operating revenues..........................................  $13,196   $8,141
Purchases...................................................   12,060    7,191
Operating expenses..........................................      899      742
Equity income from investments..............................       23       20
EBIT........................................................      260      228
Refined product sales (millions of barrels).................      316      287
</TABLE>

     YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999.  The
increase in operating revenues of $5,055 million results from increased prices
and volumes. Sales volumes of refined products, including products purchased
from others, was up 10 percent over 1999.

     Purchases increased by $4,869 million, also due to increased prices and
volumes, resulting in a gross profit increase of $186 million. The increased
operating expenses result primarily from increased repairs and maintenance
expenses, higher fuel costs and other increases at the refineries due to the
increased volumes processed. The gross profit increase primarily results from
improved margins on product sales; increased sales volumes; a gain from the sale
of 49 percent of a petrochemical facility and an increase in margins from the
sales, trading and exchanging of third-party products.

     Crude throughput at our refineries averaged 483 MBbls/d in 2000 compared to
451 MBbls/d in 1999. The increase was due to the expansion at our Aruba
refinery.

                                        20
<PAGE>   23

EXPLORATION AND PRODUCTION

     Exploration and production operations involve the exploration, development
and production of natural gas, crude oil, condensate and natural gas liquids.

     Below are the exploration and production operating results and an analysis
of these results for the years ended December 31, 2000 and 1999:

<TABLE>
<CAPTION>
                                                               2000      1999
                                                              -------   -------
                                                                (IN MILLIONS)
<S>                                                           <C>       <C>
Operating revenues..........................................  $ 1,083   $   584
Purchases...................................................        6         3
Operating expenses..........................................      651       395
EBIT........................................................      426       186
Natural gas production (MMcf/d).............................      899       632
Oil, condensate and natural gas liquids production
  (Bbls/d)..................................................   17,731    12,261
Average realized sales price (dollars):
  Gas (per Mcf).............................................  $  2.81   $  2.17
  Oil, condensate and natural gas liquids (per barrel)......    24.86     14.48
</TABLE>

     YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999.  The
increase in operating revenues of $499 million is a result of increased prices
and volumes for natural gas, crude oil, condensate and natural gas liquids.
Revenue increases included $409 million for natural gas and $96 million for
crude oil, condensate and natural gas liquids, partially offset by other revenue
decreases. The increase in operating expenses is the result of increased
production volumes and a higher rate for depreciation, depletion and
amortization. Average daily net production of natural gas increased by 42
percent over 1999, and net production of crude oil, condensate and natural gas
liquids increased by 45 percent over the prior year. The volume increases result
from our ongoing successful programs in the Texas Coastal Plain, the Gulf of
Mexico and the Rocky Mountains.

     For the sixth year in a row, we added reserves that were more than triple
production.

POWER

     Power operations include the ownership of, participation in and operation
of power projects in the United States and internationally. Power's operating
results and an analysis of those results for the years ended December 31, 2000
and 1999 are as follows:

<TABLE>
<CAPTION>
                                                              2000    1999
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Operating revenues..........................................  $167    $128
Operating expenses..........................................   134     113
Equity income from investments..............................   109      74
EBIT........................................................   142      89
</TABLE>

     YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999.  The
increase in operating revenues of $39 million results primarily from a $17
million gain due to the disposition of our interest in a Guatemala power
facility, an increase from the El Salvador operations due primarily to higher
prices, and revenues from the ManChief facility in Colorado which began
operations in July 2000. The EBIT increase of $53 million is the result of the
higher operating revenues and increased income from equity investments partially
offset by increased operating expenses of $21 million. The increase for
operating expenses of $17 million results primarily from the El Salvador
operations which incurred higher fuel and rent costs. Depreciation, depletion
and amortization increased by $4 million due to the ManChief facility which
began operations in 2000, and the Rensselaer operations which were purchased in
1999. Equity income from investments increased as a result of our purchase of an
additional 23 percent ownership in the Midland Cogeneration project in January
2000 and increased earnings from foreign investments.

                                        21
<PAGE>   24

     Our net generating capacity in operation on December 31, 2000, was 2,049
megawatts, up 43 percent from December 31, 1999.

COAL

     Coal operations include mining, processing and marketing of coal from our
reserves and from other sources, and the brokering of coal for others.

     Coal's operating results and an analysis of those results for the year
ended December 31, 2000 and 1999 are as follows:

<TABLE>
<CAPTION>
                                                              2000    1999
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Operating revenues..........................................  $277    $258
Operating expenses..........................................   274     242
EBIT........................................................     3      16
Captive and brokered sales (millions of tons)...............  10.1     9.5
</TABLE>

     YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31,
1999.  Operating revenues increased by $19 million as a result of increased
volumes partially offset by lower prices. The increase in operating expenses,
which include coal costs, was primarily due to the increased volumes sold and an
$8 million charge for impaired assets. The segment experienced a 9 percent
increase in captive volumes sold and a 3 percent decrease in the average sale
price per ton as compared to 1999.

CORPORATE AND OTHER

     Corporate and other operations involve real estate and corporate income and
expense not allocated to the operating segments.

     YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999.  The
increased loss before interest, income taxes and other charges of $50 million is
the result of merger-related charges and increased expenses from financing
activities.

                           INTEREST AND DEBT EXPENSE

     YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999.  The
interest and debt expense increase of $87 million results from higher average
debt outstanding and increased average interest rates partially offset by
increased capitalized interest.

                               MINORITY INTEREST

     YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999.  The
$28 million increase for minority interest is primarily due to the return to
limited partners related to a partnership created in late 1999.

                               INCOME TAX EXPENSE

     Income taxes fluctuated as a result of changing levels of income before
taxes and changes in the effective federal income tax rate. The effective tax
rate was 28 percent and 26 percent in 2000 and 1999. The effective federal
income tax rates were primarily affected by the exclusions for foreign
investments and several of our domestic joint ventures.

COMMITMENTS AND CONTINGENCIES

     See Item 8, Financial Statements and Supplementary Data, Notes 8 and 15,
for a discussion of our commitments and contingencies.

                                        22
<PAGE>   25

     At December 31, 2000, we had capital and investment commitments of
approximately $400 million that are expected to be funded through internally
generated funds and/or incremental borrowings. Our other planned capital and
investment projects are discretionary in nature, with no substantial capital
commitments made in advance of the actual expenditures.

                 NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

     See Item 8, Financial Statements and Supplementary Data, Note 1, for a
discussion of new accounting pronouncements we have not yet adopted.

CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE
                    SECURITIES LITIGATION REFORM ACT OF 1995

     This report contains or incorporates by reference forward-looking
statements within the meaning of the Private Securities Litigation Reform Act of
1995. Where any forward-looking statement includes a statement of the
assumptions or bases underlying the forward-looking statement, we caution that,
while we believe these assumptions or bases to be reasonable and to be made in
good faith, assumed facts or bases almost always vary from the actual results,
and the differences between assumed facts or bases and actual results can be
material, depending upon the circumstances. Where, in any forward-looking
statement, we or our management express an expectation or belief as to future
results, that expectation or belief is expressed in good faith and is believed
to have a reasonable basis. We cannot, assure you, however, that the statement
of expectation or belief will result or be achieved or accomplished. The words
"believe," "expect," "estimate," "anticipate" and similar expressions will
generally identify forward-looking statements.

                                        23
<PAGE>   26

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     We utilize derivative financial instruments to manage market risks
associated with energy commodities and interest rates. Our primary market risk
exposure is to changing energy commodity prices. We continuously manage these
risk exposures, operating under resolutions adopted by our Board of Directors.

TRADING COMMODITY PRICE RISK

     Our unregulated natural gas and power marketing and trading activities in
North America are conducted through Coastal Merchant Energy, who provides
wholesale energy services to natural gas and power clients and marketing
services to each of our business segments. Prior to October 2000, we conducted
our marketing and trading activities through Engage Energy US, L.P. and Engage
Canada, L.P., a joint venture between us and Westcoast Energy Inc., a major
Canadian natural gas company. During the fourth quarter 2000, we terminated the
Engage joint venture and commenced marketing and trading activities.

     The marketing and trading activities we conduct through Coastal Merchant
Energy offer price risk management services to the energy sector through the
sale of natural gas and electric power. These services are provided through a
variety of contracts entered into for trading purposes, including storage,
transportation, forward, future, swap and option contracts that extend for
periods up to ten years. These contracts expose us to market risk as the value
of the portfolio will change in response to changing market conditions. We
monitor and manage these risks through a variety of techniques, subject to
parameters and policies established by our management.

     We measure the risk in our commodity and energy related contracts utilizing
a Value-at-Risk Model to determine the potential unfavorable impact on earnings
due to normal market movements, and monitor our risk in comparison to
established thresholds. The Value-at-Risk computations are based on historical
simulation of price movements, which capture a significant portion of the
exposure related to open positions, and utilize historical price movements over
a specified period to project future price movements in the energy markets. We
also utilize other measures to provide additional assurance that the risks of
our commodity and energy related contracts are being properly monitored,
including sensitivity analysis, position limit control and credit, and
liquidity.

     Based on a confidence level of 95 percent and a one-day holding period, our
estimated potential one-day unfavorable impact on income before interest, income
taxes and other charges, as measured by Value-at-Risk, related to contracts held
for trading purposes was approximately $1 million at December 31, 2000. In
addition, $1 million was our highest, lowest and average estimated potential one
day unfavorable impact, as measured by Value-at-Risk, on income before interest,
income taxes and other charges for 2000. The average value represents the
average month end values. The high and low valuations represent the highest and
lowest month end values during 2000. Actual losses could exceed those measured
by Value-at-Risk.

NON-TRADING COMMODITY PRICE RISK

     We enter into swaps, futures and other contracts to hedge exposure to price
risks associated with crude oil, refined product and natural gas inventories,
commitments and various anticipated transactions. We have also entered into
hedging transactions to manage price risk relating to a portion of our future
natural gas production. At December 31, 2000, we had contracts on 161 Bcf of our
anticipated year 2001 natural gas production. Average monthly prices on these
contracts range from $2.57 to $2.69 per Mcf based on the Henry Hub price. The
table below presents the hypothetical changes in fair values arising from
immediate selected potential changes in the quoted market prices of derivative
commodity instruments outstanding at

                                        24
<PAGE>   27

December 31, 2000 and 1999. Gain or loss on these derivative commodity
instruments would be offset by a corresponding gain or loss on the hedged
commodity positions, which are not included in the table.

<TABLE>
<CAPTION>
                                           NO CHANGE      10% INCREASE         10% DECREASE
                                           ---------   ------------------   ------------------
                                             FAIR      FAIR     INCREASE    FAIR     INCREASE
IMPACT OF CHANGES IN COMMODITY PRICES ON:    VALUE     VALUE   (DECREASE)   VALUE   (DECREASE)
-----------------------------------------  ---------   -----   ----------   -----   ----------
                                                              (IN MILLIONS)
<S>                                        <C>         <C>     <C>          <C>     <C>
Derivative commodity instruments
  2000.................................      $(665)    $(785)    $(120)     $(545)     $120
  1999.................................         22         5       (17)        38        16
</TABLE>

INTEREST RATE RISK

     We use fixed and variable rate debt to partially finance budgeted
expenditures and mandatory debt retirements. These agreements expose us to
market risk related to changes in interest rates. Derivative financial
instruments, specifically interest rate swaps, are used to reduce and manage
this risk. We have entered into a number of interest rate swap agreements
designated as a partial hedge of our portfolio of variable rate debt.

     The following table presents hypothetical changes in fair values in our
debt obligations and other market sensitive financial instruments at December
31, 2000 and 1999. The modeling technique used measures the change in fair
values arising from selected changes in interest rates. Market changes reflect
immediate hypothetical changes in interest rates at December 31. Fair values are
calculated as the net present value of the expected cash flows of the financial
instrument.

<TABLE>
<CAPTION>
                                                             10% INCREASE          10% DECREASE
                                                          -------------------   -------------------
                                                FAIR       FAIR     INCREASE     FAIR     INCREASE
                                                VALUE     VALUE    (DECREASE)   VALUE    (DECREASE)
                                              ---------   ------   ----------   ------   ----------
                                                                  (IN MILLIONS)
<S>                                           <C>         <C>      <C>          <C>      <C>
Impact of changes in market rates of interest on
Assets

  Notes receivable and marketable debt
     securities
     2000...................................   $  307     $  299     $  (8)     $  317      $ 10
     1999...................................      306        299        (7)        313         7

Liabilities
  Long-term debt subject to fixed interest
     rates
     2000...................................   $4,501     $4,359     $(142)     $4,654      $153
     1999...................................    3,550      3,411      (139)      3,702       152
Securities of Subsidiaries
  Preferred securities of a consolidated
     trust
     2000...................................   $  293     $  276     $ (17)     $  311      $ 18
     1999...................................      276        260       (16)        294        18
</TABLE>

     We are not subject to fair value risk resulting from changes in market
rates of interest on our portfolio of variable rate obligations, including notes
payable, long-term debt, other commitments and variable to fixed swaps with an
aggregate fair value of approximately $2,440 million at December 31, 2000.
However, variable rate obligations do expose us to possible increases in
interest expense and decreases in earnings if interest rates were to rise. If
interest rates were to immediately increase by 10% from the December 31, 2000
levels and continue through 2001 assuming no changes in debt levels, interest
expense, including the effects of interest rate swaps, would increase by
approximately $17 million with a corresponding decrease in income before taxes,
as compared to a $12 million increase at December 31, 1999.

     We also hold various equity securities that expose us to price risk
associated with equity security markets. These securities are carried at their
fair value of $20 million at December 31, 2000. An immediate decrease in the
market prices of these securities of 10% would result in a fair value of
approximately $18 million, or a decrease in income before taxes of approximately
$2 million. The potential loss at December 31, 1999 was also approximately $2
million.

                                        25
<PAGE>   28

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                      EL PASO CGP COMPANY AND SUBSIDIARIES

                       CONSOLIDATED STATEMENTS OF INCOME
                    (IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
                                                                YEAR ENDED DECEMBER 31,
                                                              ----------------------------
                                                               2000       1999       1998
                                                              -------    -------    ------
<S>                                                           <C>        <C>        <C>
Operating revenues..........................................  $18,014    $10,331    $9,404
                                                              -------    -------    ------
Operating expenses
  Purchases.................................................   14,134      7,282     6,413
  Operating and general expenses............................    2,028      1,684     1,668
  Depreciation, depletion and amortization..................      667        483       450
                                                              -------    -------    ------
                                                               16,829      9,449     8,531
                                                              -------    -------    ------
Other income, net...........................................      191        146        94
                                                              -------    -------    ------
Income before interest, income taxes and other charges......    1,376      1,028       967
                                                              -------    -------    ------
Other expenses
  Interest and debt expense.................................      410        323       295
  Minority interest.........................................       60         32        23
  Income taxes..............................................      252        174       167
                                                              -------    -------    ------
                                                                  722        529       485
                                                              -------    -------    ------
Income from continuing operations...........................      654        499       482
Discontinued operations, net of income taxes
  Loss from operations......................................       --         --        (3)
  Estimated loss on disposal................................       --         --       (35)
                                                              -------    -------    ------
Net income..................................................      654        499       444
Dividends on preferred stock................................       --         --         6
                                                              -------    -------    ------
Net income available to common stockholders.................  $   654    $   499    $  438
                                                              =======    =======    ======
Basic earnings per share
  Income from continuing operations.........................  $  3.05    $  2.34    $ 2.24
  Discontinued operations...................................       --         --      (.18)
                                                              -------    -------    ------
  Net income................................................  $  3.05    $  2.34    $ 2.06
                                                              =======    =======    ======
Diluted earnings per share
  Income from continuing operations.........................  $  2.96    $  2.30    $ 2.21
  Discontinued operations...................................       --         --      (.18)
                                                              -------    -------    ------
  Net income................................................  $  2.96    $  2.30    $ 2.03
                                                              =======    =======    ======
  Basic average common shares outstanding...................      214        213       213
                                                              =======    =======    ======
  Diluted average common shares outstanding.................      221        217       216
                                                              =======    =======    ======
</TABLE>

                            See accompanying notes.

                                        26
<PAGE>   29

                      EL PASO CGP COMPANY AND SUBSIDIARIES

                          CONSOLIDATED BALANCE SHEETS
                      (IN MILLIONS, EXCEPT SHARE AMOUNTS)

<TABLE>
<CAPTION>
                                                                 DECEMBER 31,
                                                              ------------------
                                                               2000       1999
                                                              -------    -------
<S>                                                           <C>        <C>
                                     ASSETS

Current assets
  Cash and cash equivalents.................................  $    74    $    44
  Receivables, less allowance for doubtful accounts of $11
    million in 2000 and $17 million in 1999.................    3,051      1,933
  Inventories...............................................      867        733
  Assets from price risk management activities..............      544         --
  Prepaid expenses and other................................      207        214
                                                              -------    -------
        Total current assets................................    4,743      2,924
                                                              -------    -------
Property, plant and equipment -- at cost
  Natural gas systems.......................................    6,508      6,329
  Refining, crude oil and chemical facilities...............    2,606      2,555
  Gas and oil properties -- at full-cost....................    5,100      3,832
  Other.....................................................      672        581
                                                              -------    -------
                                                               14,886     13,297
  Accumulated depreciation, depletion and amortization......    4,248      3,960
                                                              -------    -------
        Property, plant and equipment, net..................   10,638      9,337
                                                              -------    -------
Other assets
  Goodwill..................................................      433        452
  Investments -- equity method..............................    1,596      1,435
  Other.....................................................    1,159        975
                                                              -------    -------
        Total other assets..................................    3,188      2,862
                                                              -------    -------
        Total assets........................................  $18,569    $15,123
                                                              =======    =======

                      LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities
  Notes payable.............................................  $   798    $   106
  Accounts payable..........................................    3,189      2,350
  Accrued expenses..........................................      528        420
  Liabilities from price risk management activities.........      546         --
  Current maturities on long-term debt......................      147        162
                                                              -------    -------
        Total current liabilities...........................    5,208      3,038
                                                              -------    -------
Debt
  Long-term debt, excluding current maturities..............    5,296      4,798
                                                              -------    -------
Deferred credits and other
  Deferred income taxes.....................................    1,957      1,814
  Other deferred credits....................................      807        785
                                                              -------    -------
                                                                2,764      2,599
                                                              -------    -------
Securities of subsidiaries
  Company-obligated preferred securities of a consolidated
    trust...................................................      300        300
  Preferred stock issued by subsidiaries....................      165        165
  Consolidated joint venture................................      286        286
                                                              -------    -------
                                                                  751        751
                                                              -------    -------
Stockholders' equity
  Cumulative preferred stock (with aggregate liquidation
    preference of $7 million)...............................       --         --
  Class A common stock -- Issued (2000 -- 311,377 shares;
    1999 -- 345,019 shares).................................       --         --
  Common stock -- Issued (2000 -- 219,604,836 shares;
    1999 -- 217,705,249 shares).............................       73         72
  Additional paid-in capital................................    1,044      1,032
  Retained earnings.........................................    3,565      2,965
                                                              -------    -------
                                                                4,682      4,069
  Less common stock in treasury -- at cost
    (2000 -- 4,394,651 shares; 1999 -- 4,395,950 shares)....      132        132
                                                              -------    -------
        Total stockholders' equity..........................    4,550      3,937
                                                              -------    -------
        Total liabilities and stockholders' equity..........  $18,569    $15,123
                                                              =======    =======
</TABLE>

                            See accompanying notes.

                                        27
<PAGE>   30

                      EL PASO CGP COMPANY AND SUBSIDIARIES

                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (IN MILLIONS)

<TABLE>
<CAPTION>
                                                                YEAR ENDED DECEMBER 31,
                                                              ---------------------------
                                                               2000      1999      1998
                                                              -------   -------   -------
<S>                                                           <C>       <C>       <C>
Cash flows from operating activities
  Income from continuing operations.........................  $   654   $   499   $   482
  Adjustments to reconcile income to net cash from operating
    activities
    Depreciation, depletion and amortization................      667       483       450
    Deferred income tax expense.............................      203       112       152
    Undistributed earnings in equity investees..............       (3)      (39)      (41)
    Working capital and other changes
      Accounts receivable...................................     (480)     (809)      395
      Inventories...........................................     (137)     (119)      185
      Net price risk management activities..................       (4)       --        --
      Prepaid expenses and other............................       34        18        31
      Accounts payable......................................       88       661      (573)
      Accrued expenses......................................       56       111        31
      Other.................................................       55       127        34
                                                              -------   -------   -------
         Net cash provided by operating activities..........    1,133     1,044     1,146
                                                              -------   -------   -------
Cash flows from investing activities
  Purchases of property, plant and equipment................   (2,112)   (1,781)   (1,404)
  Proceeds from sale of property, plant and equipment.......       59        37        98
  Additions to investments..................................     (286)     (379)     (255)
  Proceeds from investments.................................       59        10        60
  Net from discontinued operations..........................       (1)       (3)        9
                                                              -------   -------   -------
         Net cash used in investing activities..............   (2,281)   (2,116)   (1,492)
                                                              -------   -------   -------
Cash flows from financing activities
  Increase in short-term notes..............................      217        94       123
  Redemption of preferred stock.............................       --        --      (200)
  Proceeds from issuing common stock........................       31        15         6
  Proceeds from long-term debt issues.......................    1,722     1,091       432
  Long-term debt retirements................................     (738)     (487)     (173)
  Dividends paid............................................      (54)      (54)      (56)
  Proceeds from issuing company-obligated preferred
    securities of a consolidated trust......................       --        --       300
  Proceeds from sale of interest in joint venture...........       --       285        --
  Proceeds from issuing stock of subsidiaries...............       --        65        --
                                                              -------   -------   -------
         Net cash provided by financing activities..........    1,178     1,009       432
                                                              -------   -------   -------
Increase (decrease) in cash and cash equivalents............       30       (63)       86
Cash and cash equivalents
  Beginning of period.......................................       44       107        21
                                                              -------   -------   -------
  End of period.............................................  $    74   $    44   $   107
                                                              =======   =======   =======
</TABLE>

                            See accompanying notes.

                                        28
<PAGE>   31

                      EL PASO CGP COMPANY AND SUBSIDIARIES

                CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
                (IN THOUSANDS OF SHARES AND MILLIONS OF DOLLARS)

<TABLE>
<CAPTION>
                                                                   YEAR ENDED DECEMBER 31,
                                                    ------------------------------------------------------
                                                          2000               1999               1998
                                                    ----------------   ----------------   ----------------
                                                    SHARES    AMOUNT   SHARES    AMOUNT   SHARES    AMOUNT
                                                    -------   ------   -------   ------   -------   ------
<S>                                                 <C>       <C>      <C>       <C>      <C>       <C>
Preferred stock, par value 33 1/3c per share,
  authorized 50,000,000 shares cumulative
  convertible preferred
  $1.19, Series A: Beginning balance..............       53   $  --         56   $  --         58   $   --
  Converted to common.............................       (1)     --         (3)     --         (2)      --
                                                    -------   ------   -------   ------   -------   ------
         Ending balance...........................       52      --         53      --         56       --
                                                    =======   ------   =======   ------   =======   ------
  $1.83, Series B: Beginning balance..............       58      --         61      --         68       --
  Converted to common.............................       (7)     --         (3)     --         (7)      --
                                                    -------   ------   -------   ------   -------   ------
         Ending balance...........................       51      --         58      --         61       --
                                                    =======   ------   =======   ------   =======   ------
  $5.00, Series C: Beginning balance..............       27      --         28      --         30       --
  Converted to common.............................       (1)     --         (1)     --         (2)      --
                                                    -------   ------   -------   ------   -------   ------
         Ending balance...........................       26      --         27      --         28       --
                                                    =======   ------   =======   ------   =======   ------
Cumulative preferred
  $2.125, Series H, liquidation amount of $25 per
    share
         Beginning balance........................       --      --         --      --      8,000        3
         Redeemed.................................       --      --         --      --     (8,000)      (3)
                                                    -------   ------   -------   ------   -------   ------
         Ending balance...........................       --      --         --      --         --       --
                                                    =======   ------   =======   ------   =======   ------
Class A common stock, par value 33 1/3c per share,
  authorized 2,700,000 shares
  Beginning balance...............................      345      --        354      --        366       --
  Converted to common.............................      (35)     --        (12)     --        (13)      --
  Conversion of preferred stock and exercise of
    stock options.................................        1      --          3      --          1       --
                                                    -------   ------   -------   ------   -------   ------
         Ending balance...........................      311      --        345      --        354       --
                                                    =======   ------   =======   ------   =======   ------
Common stock, par value 33 1/3c per share,
  authorized 500,000,000 shares
  Beginning balance...............................  217,705      72    216,765      72    110,117       37
  Conversion of preferred stock...................       72      --         65      --         63       --
  Conversion of Class A common stock..............       35      --         12      --         13       --
  Two-for-one stock split.........................       --      --         --      --    106,274       35
  Exercise of stock options.......................    1,793       1        863      --        298       --
                                                    -------   ------   -------   ------   -------   ------
         Ending balance...........................  219,605      73    217,705      72    216,765       72
                                                    =======   ------   =======   ------   =======   ------
Additional paid-in capital
  Beginning balance...............................            1,032              1,016               1,243
  Exercise of stock options.......................               12                  9                   5
  Two-for-one stock split.........................               --                 --                 (35)
  Redemption of Series H preferred stock..........               --                 --                (197)
  Issuance of FELINE PRIDES(SM)...................               --                  7                  --
                                                              ------             ------             ------
         Ending balance...........................            1,044              1,032               1,016
                                                              ------             ------             ------
Retained earnings
  Beginning balance...............................            2,965              2,520               2,132
  Net income for period...........................              654                499                 444
  Cash dividends on preferred stock...............               --                 --                  (6)
  Cash dividends on Class A common stock, 22.5c
    (2000), 22.5c (1999) and 21.38c (1998) per
    share.........................................               --                 --                  --
  Cash dividends on common stock, 25c (2000), 25c
    (1999) and 23.75c (1998) per share............              (54)               (54)                (50)
                                                              ------             ------             ------
         Ending balance...........................            3,565              2,965               2,520
                                                              ------             ------             ------
Less treasury stock -- at cost....................    4,395     132      4,396     132      4,396      132
                                                    =======   ------   =======   ------   =======   ------
         TOTAL....................................            $4,550             $3,937             $3,476
                                                              ======             ======             ======
</TABLE>

                            See accompanying notes.

                                        29
<PAGE>   32

                      EL PASO CGP COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     Principles of Consolidation.  Our consolidated financial statements include
accounts of all wholly owned subsidiaries, after eliminating all significant
intercompany transactions. The equity method of accounting is used for
investments in which we are able to exert significant influence, but not control
over operating and financial policies. Other investments where we are unable to
exert significant influence are accounted for by the cost method.

     Cash and Cash Equivalents.  Cash equivalents include time deposits,
certificates of deposit and all highly liquid instruments with original
maturities of three months or less. Cash flows of a hedging instrument that is
accounted for as a hedge of an identifiable transaction are classified in the
same category as the cash flows from the item being hedged. We made cash
payments for interest and financing fees (net of amounts capitalized) of $427
million, $307 million and $292 million in 2000, 1999 and 1998. Cash payments for
income taxes amounted to $32 million, $10 million and $42 million for 2000, 1999
and 1998.

     Use of Estimates.  The preparation of financial statements in conformity
with generally accepted accounting principles requires us to make estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses. Our actual results are likely to differ from those estimates.

     Inventories.  Inventories of refined products and crude oil are accounted
for by the first-in, first-out cost method or market, if lower. Inventories of
natural gas are valued at market. Inventories of coal are accounted for at
average cost, or market, if lower. Inventories of materials and supplies are
accounted for at average cost.

     Natural Gas Imbalances.  Natural gas imbalances result from differences in
gas volumes received from and delivered to our transportation and storage
customers and arise when a customer delivers more or less gas into our pipeline
than they take out. We value these gas imbalances due to or from shippers and
operators at an appropriate index price. Natural gas imbalances are settled in
cash or made up in-kind, subject to the pipelines' various terms.

     Price Risk Management Activities.  We utilize derivative financial
instruments to manage market risks associated with energy commodities, interest
rates, commitments and other anticipated transactions. We engage in both trading
and non-trading commodity price risk management activities.

     Our activities for trading purposes consist of the sale of natural gas and
electric power to the energy sector, which are accounted for using the
mark-to-market method of accounting. As part of these activities, we execute
storage, transportation, forward, future, swap and over-the-counter and
exchange-traded option contracts.

     Under the mark-to-market method of accounting, commodity and energy related
contracts are reflected at quoted or estimated market value with resulting gains
and losses included in our income statement. Net gains or losses recognized in a
period result primarily from transactions originating within that period and the
impact of price movements on transactions originating in that or previous
periods. Assets and liabilities resulting from mark-to-market accounting are
included in our balance sheets, according to their term or maturity. Terms
regarding cash settlement of the contracts vary with respect to the actual
timing of cash receipts and payments. Receivables and payables resulting from
these timing differences are presented as price risk management activities in
our balance sheets. Cash inflows and outflows associated with these price risk
management activities are recognized in operating cash flows as the settlement
of transactions occurs.

     The market value of commodity and energy related contracts reflect
management's best estimate considering various factors, including closing
exchange and over-the-counter quotations, time value and volatility factors
underlying the commitments. The values are adjusted to reflect the potential
impact of liquidating our position in an orderly manner over a reasonable period
of time under present market conditions and to reflect other types of risks,
including model risk, credit risk and operational risks. In the absence of
quoted market prices, we utilize other valuation techniques to estimate fair
value. The use of these techniques

                                        30
<PAGE>   33

requires us to make estimations of future prices and other variables, including
market volatility, price correlation, and market liquidity. Changes in these
estimates could have a significant impact on the underlying market valuation and
could materially impact these estimates.

     We frequently enter into swaps, futures and other contracts to hedge the
price risks associated with inventories, commitments and other anticipated
transactions in connection with our non-trading activities. We defer the impact
of changes in the market value of these contracts until such time as the hedged
transaction is completed. At that time, the impact of the changes in the fair
value of these contracts is recognized in income. We also enter into interest
rate and foreign currency swaps to manage interest rates and foreign currency
exchange risk. Income and expense related to interest rate swaps is accrued as
interest rates change and is recognized in income over the life of the
agreement. Such gains and losses are essentially offset by gains or losses on
the related debt.

     To qualify as a hedge, the item to be hedged must expose us to price,
interest rate or foreign currency exchange rate risk and the hedging instrument
must reduce that exposure. Any contracts held or issued that do not meet the
requirements of a hedge are recorded at fair value in the balance sheet and any
changes in that fair value are recognized in income. If a contract designated as
a hedge of price risk or foreign currency exchange risk is terminated, the
associated gain or loss is deferred and recognized in income in the same manner
as the hedged item. Also, a contract designated as a hedge of an anticipated
transaction that is no longer likely to occur is recorded at fair value and the
associated changes in fair value recognized in income. The gain or loss
associated with a terminated interest rate swap that has been designated as a
hedge of interest rate risk will continue to be recognized in interest and debt
expense over the life of the agreement.

     Property, Plant and Equipment.  Property additions include acquisition
costs, administrative costs and, where appropriate, capitalized interest
allocable to construction. Capitalized interest amounted to $55 million, $41
million and $27 million in 2000, 1999 and 1998. All costs incurred in the
acquisition, exploration and development of gas and oil properties, including
unproductive wells, are capitalized under the full-cost method of accounting.
Such costs include the costs of all unproved properties and internal costs
directly related to acquisition and exploration activities. All other general
and administrative costs, as well as production costs, are expensed as incurred.

     Depreciation, depletion and amortization (DD&A) of gas and oil properties
are provided on the unit-of-production basis whereby the unit rate for DD&A is
determined by dividing the total unrecovered carrying value of gas and oil
properties plus estimated future development costs by the estimated proved
reserves included therein, as estimated by our engineers and reviewed by
independent engineers. The average amortization rate per equivalent unit of a
thousand cubic feet of gas production for oil and gas operations was $1.015 for
2000, $.87 for 1999 and $.89 for 1998. Unamortized costs of proved properties
are subject to a ceiling that limits such costs to the estimated future net cash
flows from proved gas and oil properties, net of related income tax effects,
discounted at 10 percent. If the unamortized costs are greater than this
ceiling, any excess will be charged to DD&A expense. No such charge was required
in the periods presented. Provisions for depletion of coal properties, including
exploration and development costs, are based upon estimates of recoverable
reserves using the unit-of-production method. Provision for depreciation of
other property is primarily on a straight-line basis over the estimated useful
life of the properties. The annual rates of depreciation are as follows:

<TABLE>
<S>                                                            <C>
Refining, crude oil and chemical facilities.................    3.0%-20.0%
Gas systems.................................................    1.2%-10.0%
Coal facilities.............................................    5.0%-33.3%
Power facilities............................................    2.9%-33.3%
Transportation equipment....................................    4.5%-33.3%
Office and miscellaneous equipment..........................    3.0%-33.3%
Buildings and improvements..................................    1.3%-20.0%
</TABLE>

                                        31
<PAGE>   34

     Costs of minor property units, or components thereof, retired or abandoned
are charged or credited, net of salvage, to accumulated depreciation, depletion
and amortization. Gain or loss on sales of major property units is credited or
charged to income.

     Goodwill.  Goodwill, which primarily relates to the acquisitions of
American Natural Resources Company and CIG, amounted to $433 million at December
31, 2000, and is being amortized on a straight-line basis over a 40-year period.
Amortization expense charged to operations was approximately $19 million for
2000, 1999 and 1998.

     We evaluate impairment of goodwill in accordance with Statement of
Financial Accounting Standards (SFAS) No. 121, Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of. Under this
methodology, when an event occurs to suggest that impairment may have occurred,
we evaluate the undiscounted net cash flows of the underlying asset or entity.
If these cash flows are not sufficient to recover the value of the underlying
asset or entity plus the goodwill amount, these cash flows are discounted at a
risk-adjusted rate with any difference recorded as an impairment in our
consolidated statements of income.

     Repair and Maintenance Costs.  Repair and maintenance costs incurred in
connection with planned major maintenance activities at various refineries or
plants are accrued as a liability in a systematic and rational manner over the
period of time until the planned major maintenance activities occur. At other
refineries or plants, the cost of each major maintenance activity is capitalized
and amortized to expense in a systematic and rational manner over the estimated
period extending to the next planned major maintenance activity.

     Income Taxes.  We follow the liability method of accounting for deferred
income taxes as required by the provisions of SFAS No. 109, Accounting for
Income Taxes.

     Revenue Recognition.  Our subsidiaries recognize revenues for the sale of
their respective products in the period of delivery. Revenues for services are
recognized in the period the services are provided.

     Currency Translation.  The U.S. dollar is the functional currency for
substantially all of our foreign operations. For those operations, all gains and
losses from currency translations are included in income currently.

     Earnings Per Share.  Basic earnings per common share amounts are calculated
using the average number of common and Class A common shares outstanding during
each period. Diluted earnings per share assumes conversion of dilutive
convertible preferred stocks, issuance of shares for the FELINE PRIDES(SM) and
the exercise of all stock options having exercise prices less than the average
market price of the common stock using the treasury stock method.

     Basic and diluted earnings per share amounts and average shares entering
into the computation for 1998 reflect the two-for-one stock split of our common
stock declared on May 7, 1998.

       Accounting for Derivative Instruments and Hedging Activities.  In June of
1998, the Financial Accounting Standards Board (FASB) issued SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities. In June of 1999,
the FASB extended the adoption date of SFAS No. 133 through the issuance of SFAS
No. 137, Deferral of the Effective Date of SFAS 133. In June 2000, the FASB
issued SFAS No. 138, Accounting for Certain Derivative Instruments and Certain
Hedging Activities, which also amended SFAS No. 133. SFAS No. 133, and its
amendments and interpretations, establishes accounting and reporting standards
for derivative instruments, including derivative instruments embedded in other
contracts, and derivative instruments used for hedging activities. It requires
that we measure all derivative instruments at their fair value, and classify
them as either assets or liabilities on our balance sheet, with a corresponding
offset to income or other comprehensive income depending on their designation,
their intended use, or their ability to qualify as hedges under the standard.

     We adopted SFAS No. 133 beginning January 1, 2001, and applied the standard
to all derivative instruments that existed on that date, except for derivative
instruments embedded in other contracts. As

                                        32
<PAGE>   35

provided for in SFAS No. 133, we applied the provisions of the standard to
derivative instruments embedded in other contracts issued, acquired, or
substantially modified after December 31, 1998.

     We use a variety of derivative instruments to conduct both energy trading
activities and to hedge risks associated with commodity prices, foreign
currencies and interest rates. The derivative instruments we use in commodity
trading activities are currently recorded at their fair value in our financial
statements under the provisions of Emerging Issues Task Force Issue No. 98-10,
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities. As a result, SFAS No. 133 did not impact our accounting for the
instruments used in commodity trading activities.

     Based on commodity prices and interest rates existing at December 31, 2000,
the impact of our adoption of SFAS 133 was a charge to other comprehensive
income, net of tax, of $459 million and an increase in net income of $3 million,
with an increase in assets of $338 million and an increase in liabilities of
$794 million. This represents the fair value of our derivative instruments
designated as cash flow hedges. The majority of the initial charge related to
contracts to sell natural gas we expect to produce through the end of 2001.

  Accounting for Transfers and Servicing of Financial Assets and Extinguishments
of Liabilities

     In September 2000, the FASB issued SFAS No. 140, Accounting for Transfers
and Servicing of Financial Assets and Extinguishments of Liabilities, which
replaces SFAS No. 125. This statement revises the standards for accounting for
securitizations and other transfers of financial assets and collateral and
requires certain disclosures, but carries over most of SFAS No. 125's provisions
without reconsideration. This standard has various effective dates, the earliest
of which is for fiscal years ending after December 15, 2000. We do not believe
this pronouncement will have a material effect on our financial statements.

     Reclassification of Prior Period Statements.  In 2000, we applied FASB
Emerging Issues Task Force Issue No. 99-19, Reporting Revenue Gross as a
Principal versus Net as an Agent, which resulted in the reclassification of
revenues and purchases for various trading and marketing activities that had
been previously reported on a net basis. As a result of the adoption, operating
revenues and purchases increased by $4.0 billion, $2.1 billion and $2.0 billion
in 2000, 1999 and 1998. This change had no impact on gross margins or net
income. Prior years amounts have been reclassified to conform with the new
presentation. In addition, other minor reclassifications have been made to
conform with current reporting practices. The effect of the other minor
reclassifications was not material to our financial position, operating results
or cash flows.

2. MERGER

     On January 29, 2001, we became a wholly owned subsidiary of El Paso through
our merger with a wholly owned El Paso subsidiary. In the merger, holders of our
common stock and Class A common stock received tax free 1.23 shares of El Paso
common stock for each outstanding common share; holders of our Series A and
Series B convertible preferred stock received tax free 9.133 shares of El Paso
common stock for each outstanding convertible share; and holders of our Series C
convertible preferred stock received tax free 17.98 shares of El Paso common
stock for each outstanding convertible preferred share. In addition, holders of
our outstanding stock options received shares of El Paso common stock based on
the fair value of these options on the date of the merger. These exchanges will
result in a charge of approximately $278 million that will be recorded in the
first quarter of 2001. As a result of the merger, El Paso owns 100 percent of
our common equity.

     Pursuant to the El Paso merger, we have been ordered by the Federal Trade
Commission to sell several assets. Assets we have been, or will be, required to
sell include our Gulfstream system, our interests in the Stingray and U-T
Offshore systems, and our interests in the Empire pipeline and Iroquois pipeline
systems. The sales of Gulfstream and our interests in the Stingray and U-T
Offshore systems were completed in February 2001. Proceeds from these sales were
approximately $70 million, resulting in a first quarter 2001 loss from those
sales of approximately $29 million. The sales of our interests in the Empire and
Iroquois systems are also expected to be completed in the first half 2001.

                                        33
<PAGE>   36

3. INCOME TAXES

     Pretax income from continuing operations are composed of the following:

<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31,
                                                              ------------------------
                                                               2000     1999     1998
                                                              ------   ------   ------
                                                                   (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
United States...............................................   $721     $554     $502
Foreign.....................................................    185      119      147
                                                               ----     ----     ----
                                                               $906     $673     $649
                                                               ====     ====     ====
</TABLE>

     The following table reflects the components of income tax expense from
continuing operations for the years ended December 31:

<TABLE>
<CAPTION>
                                                              2000   1999   1998
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Current
  Federal...................................................  $ 41   $ 45   $  5
  State.....................................................    (1)     9      4
  Foreign...................................................     9      8      6
                                                              ----   ----   ----
                                                                49     62     15
                                                              ----   ----   ----
Deferred
  Federal...................................................   189    112    141
  State.....................................................    11     (3)     8
  Foreign...................................................     3      3      3
                                                              ----   ----   ----
                                                               203    112    152
                                                              ----   ----   ----
          Total tax expense.................................  $252   $174   $167
                                                              ====   ====   ====
</TABLE>

     We have concluded with the Internal Revenue Service Appeals Office a
tentative settlement of the adjustments proposed to our federal income tax
returns filed for the years 1988 through 1994. Examination of our federal income
tax returns filed for the years 1995, 1996 and 1997 began in 1999 and is
ongoing. We believe that adequate provisions for federal income taxes have been
reflected in our consolidated financial statements.

     Our tax expense differs from the amount computed by applying the statutory
federal income tax rate (35 percent) to income before taxes. The following table
outlines the reasons for the differences for the periods ended December 31:

<TABLE>
<CAPTION>
                                                              2000    1999    1998
                                                              ----    ----    ----
                                                                 (IN MILLIONS)
<S>                                                           <C>     <C>     <C>
Tax expense at the statutory federal rate of 35%............  $317    $236    $227
Increase (decrease)
  Tight sands gas credit....................................    (6)     (6)     (8)
  State income tax cost.....................................     6       4       8
  Exclusion for foreign investments and domestic joint
     ventures...............................................   (48)    (52)    (50)
  Depreciation, depletion and amortization..................   (17)    (10)      5
  Other.....................................................    --       2     (15)
                                                              ----    ----    ----
          Income tax expense................................  $252    $174    $167
                                                              ====    ====    ====
          Effective tax rate................................    28%     26%     26%
                                                              ====    ====    ====
</TABLE>

                                        34
<PAGE>   37

     The following are the components of our net deferred tax liability at
December 31:

<TABLE>
<CAPTION>
                                                               2000     1999
                                                              ------   ------
                                                               (IN MILLIONS)
<S>                                                           <C>      <C>
Deferred tax liabilities
  Excess of book basis over tax basis of property, plant and
     equipment..............................................  $1,825   $1,646
  Pensions and benefit costs................................     160      130
  Other.....................................................      71      130
                                                              ------   ------
          Total deferred tax liability......................   2,056    1,906
                                                              ------   ------
Deferred tax assets
  Purchase gas and other recoverable costs..................      --        5
  Alternative minimum tax credit carryforward...............     212      190
                                                              ------   ------
          Total deferred tax assets.........................     212      195
                                                              ------   ------
          Net deferred tax liability........................  $1,844   $1,711
                                                              ======   ======
</TABLE>

     U.S. income taxes have been provided for earnings of foreign subsidiaries
that are expected to be distributed to the U.S. parent company. Foreign
subsidiaries' cumulative undistributed earnings of $533 million are considered
to be indefinitely reinvested outside the U.S. and, accordingly, no U.S. income
taxes have been provided on those earnings. The determination of the
hypothetical amount of unrecognized deferred U.S. taxes on undistributed
earnings of foreign subsidiaries is not practicable.

4. EARNINGS PER SHARE

     Basic and diluted earnings per share amounts calculated in accordance with
SFAS No. 128 Earnings Per Share, are presented below for the years ended
December 31:

<TABLE>
<CAPTION>
                                              2000              1999              1998
                                         ---------------   ---------------   ---------------
                                         BASIC   DILUTED   BASIC   DILUTED   BASIC   DILUTED
                                         -----   -------   -----   -------   -----   -------
                                           (IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<S>                                      <C>     <C>       <C>     <C>       <C>     <C>
Income from continuing operations......  $ 654    $ 654    $ 499    $ 499    $ 482    $ 482
  Preferred stock dividends............     --       --       --       --        6        6
                                         -----    -----    -----    -----    -----    -----
Adjusted income from continuing
  operations...........................  $ 654    $ 654    $ 499    $ 499    $ 476    $ 476
                                         =====    =====    =====    =====    =====    =====
Average common shares outstanding......    214      214      213      213      213      213
Effect of diluted securities
  Stock options........................     --        4       --        3       --        2
  FELINE PRIDES(SM)....................     --        2       --       --       --       --
  Convertible preferred stock..........     --        1       --        1       --        1
                                         -----    -----    -----    -----    -----    -----
Average common shares outstanding......    214      221      213      217      213      216
                                         =====    =====    =====    =====    =====    =====
Earnings per common share
  Income from continuing operations....  $3.05    $2.96    $2.34    $2.30    $2.24    $2.21
                                         =====    =====    =====    =====    =====    =====
</TABLE>

5. PREFERRED STOCK

     On April 15, 1998, we redeemed all 8,000,000 outstanding shares of our
$2.125 Cumulative Preferred Stock, Series H. Redemption price for the Series H
stock was $25 per share plus accrued dividends of $.182986 to April 15, 1998.

                                        35
<PAGE>   38

6. STOCK-BASED COMPENSATION

     Executives, directors and other key employees have been granted options to
purchase common shares under stock option plans adopted in 1990, 1994, 1997 and
1998. Under each plan, the option price equals the fair market value of the
common shares on the date of grant. Options vest cumulatively at rates ranging
from 15% to 33 1/3% of the option shares on each anniversary date of the date of
grant beginning with the first or second anniversary. The options, which expire
either five years or ten years from the grant date, do not carry any stock
appreciation rights.

     A summary of the status of our stock options as of December 31, 2000, 1999,
and 1998 is presented below:

<TABLE>
<CAPTION>
                                                                STOCK OPTIONS
                                   ------------------------------------------------------------------------
                                            2000                     1999                     1998
                                   ----------------------   ----------------------   ----------------------
                                                 WEIGHTED                 WEIGHTED                 WEIGHTED
                                   # SHARES OF   AVERAGE    # SHARES OF   AVERAGE    # SHARES OF   AVERAGE
                                   UNDERLYING    EXERCISE   UNDERLYING    EXERCISE   UNDERLYING    EXERCISE
                                     OPTIONS      PRICES    OPTIONS(1)     PRICES    OPTIONS(1)     PRICES
                                   -----------   --------   -----------   --------   -----------   --------
<S>                                <C>           <C>        <C>           <C>        <C>           <C>
Outstanding at beginning of
  year...........................   7,113,709     $25.68     6,604,617     $22.64     5,213,310     $18.12
  Granted........................      21,268     $51.45     1,809,068     $32.93     2,080,349     $32.72
  Exercised......................  (1,800,493)    $17.99      (865,688)    $17.23      (466,812)    $16.15
  Revoked or expired.............     (57,800)    $26.43      (434,288)    $26.52      (222,230)    $23.84
                                   ----------                ---------                ---------
Outstanding at end of year.......   5,276,684     $28.40     7,113,709     $25.68     6,604,617     $22.64
                                   ==========                =========                =========
Exercisable at end of year.......   1,501,462     $26.46     1,983,595     $19.18     1,706,453     $16.01
                                   ==========                =========                =========
</TABLE>

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

(1) Includes Class A common shares

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

<TABLE>
<CAPTION>
ASSUMPTION:                                                   2000    1999    1998
-----------                                                   ----    ----    ----
<S>                                                           <C>     <C>     <C>
Expected Term in Years......................................     5       8       8
Expected Volatility.........................................  36.7%   35.8%   22.4%
Expected Dividends..........................................   0.3%    0.8%    0.6%
Risk-Free Interest Rate.....................................   5.1%    5.2%    5.6%
</TABLE>

     The Black-Scholes weighted average fair value of options granted during
2000, 1999 and 1998 was $17.79, $15.22, and $12.77.

     Options outstanding as of December 31, 2000 are summarized below:

<TABLE>
<CAPTION>
                                                         OPTIONS OUTSTANDING
                                    -------------------------------------------------------------
                                                   WEIGHTED
                                                    AVERAGE     WEIGHTED                 WEIGHTED
                                      NUMBER       REMAINING    AVERAGE                  AVERAGE
                                    OUTSTANDING   CONTRACTUAL   EXERCISE   EXERCISABLE   EXERCISE
RANGE OF EXERCISE PRICES            AT 12/31/00      LIFE        PRICE     AT 12/31/00    PRICE
------------------------            -----------   -----------   --------   -----------   --------
<S>                                 <C>           <C>           <C>        <C>           <C>
$12.97 to $18.28..................     917,344        4.6        $16.73       350,644     $15.88
$23.53 to $29.82..................     980,172        6.1        $23.63       403,878     $23.71
$30.74 to $38.63..................   3,331,431        7.6        $32.77       738,719     $32.83
$40.09 to $75.19..................      47,737        4.4        $45.96         8,221     $41.06
                                     ---------                              ---------
                                     5,276,684        6.8        $28.40     1,501,462     $26.46
                                     =========                              =========
</TABLE>

                                        36
<PAGE>   39

  Pro Forma Net Income and Net Income Per Common Share

     Had the compensation expense for our stock-based compensation plans been
determined applying the provisions of SFAS No. 123, our income from continuing
operations, net income and income per common share amounts for 2000, 1999, and
1998 would approximate the pro forma amounts below:

<TABLE>
<CAPTION>
                                         YEAR ENDED                YEAR ENDED                YEAR ENDED
                                      DECEMBER 31, 2000         DECEMBER 31, 1999         DECEMBER 31, 1998
                                   -----------------------   -----------------------   -----------------------
                                   AS REPORTED   PRO FORMA   AS REPORTED   PRO FORMA   AS REPORTED   PRO FORMA
                                   -----------   ---------   -----------   ---------   -----------   ---------
<S>                                <C>           <C>         <C>           <C>         <C>           <C>
Income from continuing
  operations.....................     $ 654        $ 645        $ 499        $ 487        $ 482        $ 474
Net income.......................     $ 654        $ 645        $ 499        $ 487        $ 438        $ 435
Basic income per common share
  from continuing operations.....     $3.05        $3.01        $2.34        $2.28        $2.24        $2.20
Basic income per common share....     $3.05        $3.01        $2.34        $2.28        $2.06        $2.02
Diluted income per common share
  from continuing operations.....     $2.96        $2.92        $2.30        $2.24        $2.21        $2.17
Diluted income per common
  share..........................     $2.96        $2.92        $2.30        $2.24        $2.03        $1.99
</TABLE>

     The effects of applying SFAS No. 123 in this pro forma disclosure are not
indicative of future amounts. SFAS No. 123 does not apply to awards granted
prior to the 1995 fiscal year.

     Stock options available for future grants amounted to 5,510,041; 5,478,587;
and 6,856,789 at December 31, 2000, 1999 and 1998. Exercisable stock options
amounted to 1,501,462; 1,983,595; and 1,706,453 at December 31, 2000, 1999 and
1998.

     At the time of our merger with El Paso, holders of our outstanding stock
options received shares of El Paso common stock based on the fair value of these
options on the date of the merger, as determined in accordance with the merger
agreement. A total of approximately 4 million shares were issued in exchange for
these options.

7. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES

     Our operations involve managing market risks related to changes in interest
rates, foreign exchange rates and commodity prices. Derivative financial
instruments, specifically swaps and other contracts, are used to reduce and
manage those risks.

FAIR VALUE OF FINANCIAL INSTRUMENTS

     We have estimated the fair value amounts of our financial instruments using
appropriate market information and valuation methodologies. Considerable
judgment is required to develop the estimates of fair value; thus, the estimates
provided herein are not necessarily indicative of the amounts that we could
realize in a current market exchange. The carrying amounts and estimated fair
values of our financial instruments at December 31 are as follows:

<TABLE>
<CAPTION>
                                                           2000                1999
                                                     -----------------   -----------------
                                                     CARRYING    FAIR    CARRYING    FAIR
                                                      AMOUNT    VALUE     AMOUNT    VALUE
                                                     --------   ------   --------   ------
                                                                 (IN MILLIONS)
<S>                                                  <C>        <C>      <C>        <C>
Nonderivatives
  Financial assets
     Cash and cash equivalents.....................   $   74    $   74    $   44    $   44
     Notes receivable..............................      245       272       259       271
     Investments...................................       70        70        68        68
</TABLE>

                                        37
<PAGE>   40

<TABLE>
<CAPTION>
                                                           2000                1999
                                                     -----------------   -----------------
                                                     CARRYING    FAIR    CARRYING    FAIR
                                                      AMOUNT    VALUE     AMOUNT    VALUE
                                                     --------   ------   --------   ------
                                                                 (IN MILLIONS)
<S>                                                  <C>        <C>      <C>        <C>
  Financial liabilities
     Short-term debt...............................      798       798       106       106
     Long-term debt................................    5,443     5,551     4,960     4,907
  Company-obligated preferred securities of a
     consolidated trust............................      300       293       300       276
Derivatives relating to
  Non-Trading......................................
     Commodity swaps gain (loss)...................       --      (692)       --        (5)
     Interest rate swaps gain (loss)...............       --        --        --        --
  Trading..........................................
     Commodity option contracts....................       12        12        --        --
     Futures contracts.............................       15        15        --        --
     Swap and forward contracts....................      226       226        --        --
</TABLE>

     The estimated values of our notes receivable, long-term debt, our
company-obligated preferred securities of a consolidated trust, preferred stock
issued by our subsidiaries and limited partnership interests in consolidated
joint venture are based on interest rates at December 31, 2000 and 1999 for new
issues with similar remaining maturities. The fair value of investments are
based on market prices at December 31, 2000 and 1999, time value and volatility.
The fair value of the derivatives related to commodity swaps and commodity
options are derived from various factors, including quoted market prices at
December 31, 2000 and 1999. The fair market value of our interest rate swaps is
based on the estimated termination values at December 31, 2000 and 1999.

TRADING COMMODITY ACTIVITIES

     Our trading business offers price risk management services to the energy
sector through the sale of natural gas and electric power. These services are
provided through a variety of contracts entered into for trading purposes,
including storage, transportation, forward, future, swap and option contracts
that extend for periods up to ten years. These contracts expose us to market
risk as the value of the portfolio will change in response to changing market
conditions.

     The fair value of commodity and energy related contracts entered into for
trading purposes as of December 31, 2000 and the average fair value of those
instruments held during the year then ended are as follows:

<TABLE>
<CAPTION>
                                                                              AVERAGE FAIR
                                                                                VALUE FOR
                                                                             THE YEAR ENDED
                       2000                          ASSETS   LIABILITIES   DECEMBER 31, 2000
                       ----                          ------   -----------   -----------------
                                                                  (IN MILLIONS)
<S>                                                  <C>      <C>           <C>
Futures contracts..................................   $ 15       $ --             $ (3)
Options contracts..................................     59         47                9
Swaps and forward contracts........................    516        290              170
</TABLE>

     The absolute notional volume of our swap and over-the-counter option
contracts was 1,385 and 59 Bcf at December 31, 2000. Of this total, we are a
fixed price payor on 767 Bcf and a fixed price receiver on 677 Bcf. These
notional volumes, which have a maximum term of nine years, do not represent
volumes exchanged by the parties, and therefore, are not a measurement of our
exposure to market or credit risks.

     We are exposed to credit risk, as well as market risk, on these contracts.
Credit risk is the risk of loss from nonperformance by suppliers, customers or
financial counterparties to a contract. Terms regarding cash settlements of
these transactions vary based upon the contractual terms. We monitor and manage
these risks

                                        38
<PAGE>   41

through a variety of techniques, including daily reporting of credit exposure
and portfolio value to our management.

     The counterparties associated with our assets from price risk management
activities are summarized as follows:

<TABLE>
<CAPTION>
                                                   ASSETS FROM PRICE RISK MANAGEMENT ACTIVITIES
                                                             AS OF DECEMBER 31, 2000
                                                  ----------------------------------------------
                                                                            BELOW
                                                  INVESTMENT GRADE    INVESTMENT GRADE    TOTAL
                                                  -----------------   -----------------   ------
                                                                  (IN MILLIONS)
<S>                                               <C>                 <C>                 <C>
Gas and electric utilities......................        $ 62                 $14           $ 76
Energy marketers................................         214                  26            240
Financial institutions..........................         372                  --            372
Independent power producers.....................          13                  --             13
Oil and gas producers...........................          29                   1             30
Industrials.....................................           5                  --              5
Pipelines and other.............................          45                  --             45
                                                        ----                 ---           ----
          Total assets from price risk
            management activities...............        $740                 $41           $781
                                                        ====                 ===           ====
</TABLE>

     Investment grade is primarily determined using publicly available credit
ratings along with a consideration of collateral, which encompass standby
letters of credit, parent company guarantees and property interests.

     The concentration of our counterparties in the energy industry may impact
our overall exposure to credit risk, in that the counterparties may be similarly
affected by changes in economic, regulatory or other conditions. Based on our
policies and risk exposure, we believe our risk is minimal as a result of
counterparty nonperformance.

NON-TRADING PRICE RISK MANAGEMENT ACTIVITIES

     Interest Rate Swaps.  We have entered into a number of interest rate swap
agreements designated as a partial hedge of our portfolio of variable rate debt.
The purpose of these swaps is to fix interest rates on variable rate debt and
reduce exposures to interest rate fluctuations. At December 31, 2000, we had
interest rate swaps with a notional amount of $12 million, and a portfolio of
variable rate debt outstanding in the amount of $1,854 million. Under the
remaining agreement, we will pay the counterparty interest at a fixed rate of
6.83%, and the counterparty will pay us interest at a variable rate equal to the
London Interbank Offered Rate (LIBOR) or other market rates. The rate applicable
to this agreement was 6.485% at December 31, 2000. The notional amounts do not
represent amounts exchanged by the party, and thus are not a measure of our
exposure. The amounts exchanged are normally based on the notional amounts and
other terms of the swaps. The variable rates are subject to change over time as
market rates fluctuate. Terms expire at various dates through the year 2011.

     Neither us nor the counterparties, which are prominent bank institutions,
are required to collateralize their respective obligations under these swaps. We
are exposed to loss if one or more of the counterparties default. At December
31, 2000, we had no exposure to credit loss on interest rate swaps. We do not
believe that any reasonably likely change in interest rates would have a
material adverse effect on our financial position, operating results or cash
flows.

     Other Derivatives.  We frequently enter into swaps and other contracts to
hedge the price risks associated with inventories, commitments and various
transactions. The swaps and other contracts are with established energy
companies and major financial institutions. We believe our credit risk is
minimal on these transactions, as the counterparties are required to meet
stringent credit standards.

                                        39
<PAGE>   42

     The absolute notional volumes and terms of our non-trading swaps at
December 31, 2000 are set forth below (natural gas volumes are in millions of
British thermal units and crude oil and refined products volumes are in millions
of barrels):

<TABLE>
<CAPTION>
                                                 FIXED PRICE   FIXED PRICE      MAXIMUM
                                                    PAYOR       RECEIVER     TERMS IN YEARS
                                                 -----------   -----------   --------------
<S>                                              <C>           <C>           <C>
Energy Commodities
  Natural gas (MMBtu)..........................    625,170     157,150,000         2
  Crude oil and refined products (MMBbls)......     19,025          13,050         1
</TABLE>

8. DEBT

     Long-Term Debt.  Our long-term debt outstanding consisted of the following
at December 31:

<TABLE>
<CAPTION>
                                                               2000     1999
                                                              ------   ------
                                                               (IN MILLIONS)
<S>                                                           <C>      <C>
El Paso CGP:
Notes payable (revolving credit agreements).................  $  135   $   50
Senior notes:
  10.375%, due 2000.........................................      --      121
  10%, due 2001.............................................      84       84
  8.125%, due 2002..........................................     250      250
  6.2%, due 2004............................................     200      200
  6.5%, due 2006............................................     200      200
  7.75%, due 2010...........................................     399       --
  7.5%, due 2006............................................     299       --
  7.625%, due 2008..........................................     215       --
  Floating rate notes, due 2002.............................     400       --
  Floating rate notes, 2003.................................     200       --
Senior debentures:
  10.25%, due 2004..........................................      38       38
  10.75%, due 2010..........................................      57       57
  9.75%, due 2003...........................................     102      102
  9.625%, due 2012..........................................     149      149
  7.75%, due 2035...........................................     150      150
  7.42%, due 2037...........................................     200      200
  6.7%, due 2027............................................     200      200
  6.5%, due 2008............................................     200      200
  6.95%, due 2028...........................................     199      199
  6.375%, due 2009..........................................     199      199
  6.625% with FELINE PRIDES(SM), due 2004...................     455      454
                                                              ------   ------
                                                               4,331    2,853
                                                              ------   ------
Subsidiary companies:
  ANR
     Debentures, 7% to 9.625%, due 2021 through 2025........     498      498
  Coastal Natural Gas Company
     Revolving credit agreement, due 2001...................      --      294
     Term loan, 13.75%, due 2010............................      14       --
  CIG
     Debentures, 6.85% and 10%, due 2005 through 2037.......     280      280
  Coastal Holding Corporation
     Term loans, due 2003...................................      --      275
  Other.....................................................     320      285
                                                              ------   ------
                                                               1,112    1,632
                                                              ------   ------
Amount reclassified from short-term debt....................      --      475
                                                              ------   ------
  Total long-term debt......................................   5,443    4,960
  Less current maturities...................................     147      162
                                                              ------   ------
Long-term debt, less current maturities.....................  $5,296   $4,798
                                                              ======   ======
</TABLE>

                                        40
<PAGE>   43

     At December 31, 2000, amounts available under our long-term credit
agreements with banks totaled $1,890 million, including $135 million available
to El Paso CGP. Loans under these agreements bear interest at money
market-related rates (weighted average 7.27% at December 31, 2000). Annual
commitment fees range up to .30% payable on the unused portion of the applicable
facility. At December 31, 2000, $303 million was outstanding, and $518 million
of the unused amount was dedicated to specific uses.

     Our availability to borrow under our credit agreements is subject to
specified conditions, which we believe we currently meet. These conditions
include compliance with the financial covenants and ratios required by such
agreements, absence of default under such agreements, and continued accuracy of
the representations and warranties contained in such agreements (including the
absence of any material adverse changes).

     Several of our agreements, totaling $1,500 million, have been terminated
subsequent to our merger with El Paso, and we became a borrower under El Paso's
$2 billion 364-day renewable credit and competitive advance facility and $1
billion 3-year revolving credit and competitive advance facility. The interest
rate for these facilities varies and would have been LIBOR plus 50 basis points
as of December 31, 2000.

     Our subsidiary project financing notes bear interest at money
market-related rates.

     In September 2000, we issued $215 million of 7.625% Notes due in 2008. The
net proceeds from the sale of the Notes were used for general corporate
purposes, including the repayment of short-term borrowings.

     In August 2000, we issued $300 million of 7.5% Notes due in 2006. The net
proceeds from the sale of the Notes were used for general corporate purposes,
including the repayment of floating rate indebtedness.

     In July 2000, we issued $200 million of Floating Rate Notes due in 2003.
The Notes bear interest at a rate equal to the three-month LIBOR plus 0.60%. The
net proceeds from the sale were used for general corporate purposes, including
the repayment of floating rate indebtedness.

     In June 2000, we issued $400 million of 7.75% Notes due in 2010. The net
proceeds from the sale of the Notes were used to repay floating rate
indebtedness, including indebtedness of a subsidiary under a revolving credit
facility, and for general corporate purposes.

     In March 2000, we issued $400 million of Floating Rate Notes due in 2002.
The Notes bear interest at a rate equal to the three-month LIBOR plus 0.45%. The
net proceeds from the sale of the Notes were used for general corporate
purposes, including the repayment of indebtedness.

     In August 1999, we issued a total of 18,400,000 FELINE PRIDES(SM)
consisting of 17,000,000 Income PRIDES with a stated value of $25 and 1,400,000
Growth PRIDES with a stated value of $25. The Income PRIDES consist of a unit
comprised of a Senior Debenture and a purchase contract under which the holder
is obligated to purchase from us by no later than August 16, 2002 for $25 (the
stated price) a number of shares of our common stock. The Growth PRIDES consist
of a unit comprised of a purchase contract under which the holder is obligated
to purchase from us by no later than August 16, 2002 for $25 (the stated price)
a number of shares of our common stock and a 2.5% undivided beneficial interest
in a three-year Treasury security having a principal amount at maturity equal to
$1,000. Under the terms of the purchase contract in effect prior to the merger
with El Paso, the number of shares of common stock the holder of a PRIDE
received varied between .5384 and .6568 shares, depending on the price of our
common stock.

     Under the terms of the purchase contract, as a result of the merger with El
Paso, the holder of a PRIDE is entitled and required to receive upon settlement
 .6622 shares of El Paso common stock. This will result in the issuance of
approximately 12.2 million shares of El Paso common stock. The obligation of a
holder of PRIDES to purchase common stock is secured by a pledge of the Senior
Debenture or Treasury security.

     Various agreements contain restrictive covenants which, among other things,
limit dividends by several of our subsidiaries and additional indebtedness of
several subsidiaries. At December 31, 2000, net assets of our consolidated
subsidiaries amounted to approximately $12 billion, of which $623 million was
restricted by these provisions. There will be no restricted amount subsequent to
the merger with El Paso due to the termination of the long-term credit
agreements under which these restrictions arose.

                                        41
<PAGE>   44

     Maturities.  Aggregate maturities of the principal amounts of long-term
debt for the next five years and in total thereafter are as follows:

<TABLE>
<CAPTION>
                                                           (IN MILLIONS)
                                                           -------------
<S>                                                        <C>
2001.....................................................     $  147
2002.....................................................        819
2003.....................................................        316
2004.....................................................        711
2005.....................................................        369
Thereafter...............................................      3,081
                                                              ------
     Total long-term debt, including current
       maturities........................................     $5,443
                                                              ======
</TABLE>

     Notes Payable.  At December 31, 2000, we had $798 million of outstanding
indebtedness under our commercial paper program and indebtedness to banks under
short-term lines of credit, compared to $581 million at December 31, 1999. For
December 31, 1999, our financial statements reflected $475 million of short-term
borrowings that had been reclassified as long-term, based on the availability of
committed credit lines with maturities in excess of one year and our intent to
maintain such amounts as long-term borrowings. The weighted average interest
rates were 7.15% and 6.63% at December 31, 2000 and 1999, respectively. As of
December 31, 2000, $622 million was available to be drawn under short-term
credit lines.

     Restrictions on Payment of Dividends.  Under the terms of the most
restrictive of our financing agreements, approximately $900 million of retained
earnings was available at December 31, 2000, for payment of dividends on our
common and preferred stocks.

     Guarantees.  We have guaranteed specific obligations of several of our
unconsolidated affiliates. Affiliates are generally not required to
collateralize their contingent liabilities to us. At December 31, 2000, the
outstanding principal balance under these guarantees was $165 million.
Additionally, we and a former partner have issued a number of trade guarantees
related to the operations of the Engage Energy US, L.P. and Engage Energy
Canada, L.P. joint venture. The joint venture terminated in the fourth quarter
2000, with each of the former partners retaining a portion of the operations. As
a condition to the termination, each of the former partners agreed to a
continuation of the guarantees that were issued in connection with the
operations retained by the other partner. These guarantees are to be replaced as
soon as practical, and in any event, by July 2001. Each party has agreed to
reimburse the other for any payments that are made under these guarantees. As of
December 31, 2000, we had outstanding guarantees in the principal amount of $61
in connection with the operations of the Engage joint venture that were
transferred to the other party. We believe that the actual potential liability
is significantly less than the principal amount of these guarantees. We are of
the opinion that these parties will be able to perform under the guaranteed
transactions, that no payments will be required and that no losses will be
incurred under such guarantees.

9. RETIREMENT BENEFITS

  Pension Benefits

     We have non-contributory pension plans covering substantially all of our
U.S. employees. These plans provide benefits based on final average monthly
compensation and years of service, subject to maximum limitations as defined in
the plans.

  Postretirement Benefits

     We provide certain health care and life insurance benefits for
substantially all of our U.S. employees. The estimated costs of retiree benefit
payments are accrued during the years the employee provides services.

                                        42
<PAGE>   45

     The following table sets forth the change in benefit obligation, change in
plan assets, reconciliation of funded status, and components of net periodic
benefit cost for pension benefits and other postretirement benefits.

<TABLE>
<CAPTION>
                                                                            POSTRETIREMENT
                                                        PENSION BENEFITS       BENEFITS
                                                        -----------------   ---------------
                                                         2000      1999      2000     1999
                                                        -------   -------   ------   ------
                                                                   (IN MILLIONS)
<S>                                                     <C>       <C>       <C>      <C>
Change in benefit obligation
  Benefit obligation at beginning of period...........  $  777    $  758     $108     $108
  Service cost........................................      21        21        3        3
  Interest cost.......................................      59        52        8        7
  Participant contributions...........................      --        --        2        3
  Actuarial loss or (gain)............................      10       (11)       3       (3)
  Benefits paid.......................................     (45)      (43)     (10)     (10)
                                                        ------    ------     ----     ----
  Benefit obligation at end of period.................  $  822    $  777     $114     $108
                                                        ======    ======     ====     ====
Change in plan assets
  Fair value of plan assets at beginning of period....  $1,662    $1,482     $ 29     $ 24
  Actual return on plan assets........................     354       222        1        1
  Employer contributions..............................      --         1       11       10
  Administrative expenses.............................      --        --       --       (2)
  Benefits paid.......................................     (45)      (43)      (6)      (4)
                                                        ------    ------     ----     ----
  Fair value of plan assets at end of period..........  $1,971    $1,662     $ 35     $ 29
                                                        ======    ======     ====     ====
Reconciliation of funded status
  Funded status at end of period......................  $1,149    $  885     $(79)    $(79)
  Unrecognized net actuarial gain.....................    (528)     (368)     (27)     (38)
  Unrecognized net transition obligation..............     (12)      (20)      71       77
  Unrecognized prior service cost.....................       4         5        3        3
                                                        ------    ------     ----     ----
  Prepaid (accrued) benefit cost at December 31, .....  $  613    $  502     $(32)    $(37)
                                                        ======    ======     ====     ====
</TABLE>

     Benefit obligations are based upon actuarial estimates as described below.

<TABLE>
<CAPTION>
                                                                      POSTRETIREMENT
                                              PENSION BENEFITS           BENEFITS
                                            ---------------------   ------------------
                                                     YEAR ENDED DECEMBER 31,
                                            ------------------------------------------
                                            2000    1999    1998    2000   1999   1998
                                            -----   -----   -----   ----   ----   ----
                                                          (IN MILLIONS)
<S>                                         <C>     <C>     <C>     <C>    <C>    <C>
Benefit cost for the plans includes the
  following components
  Service cost............................  $  21   $  21   $  20   $  3   $ 3    $ 2
  Interest cost...........................     59      52      49      8     7      7
  Expected return on plan assets..........   (164)   (146)   (126)    (1)   (1)    (1)
  Amortization of net actuarial gain......    (20)    (13)     (8)    (2)   (2)    (3)
  Amortization of transition obligation...     (8)     (8)     (9)     6     6      6
  Amortization of prior service cost......      1       1       1      1    --      1
                                            -----   -----   -----   ----   ---    ---
  Net cost................................  $(111)  $ (93)  $ (73)  $ 15   $13    $12
                                            =====   =====   =====   ====   ===    ===
</TABLE>

                                        43
<PAGE>   46

<TABLE>
<CAPTION>
                                                            PENSION       POSTRETIREMENT
                                                            BENEFITS         BENEFITS
                                                          ------------    --------------
                                                          2000    1999    2000     1999
                                                          ----    ----    -----    -----
<S>                                                       <C>     <C>     <C>      <C>
Weighted average assumptions
  Discount rate.........................................  7.75%     8%    7.75%       8%
  Expected return on plan assets........................    10%    10%     4.3%     4.3%
  Rate of compensation increase.........................     4%     4%     N/A      N/A
</TABLE>

     Actuarial estimates for our postretirement benefits plans assumed a
weighted average annual rate of increase in the per capita costs for covered
health care benefits of 7.8 percent in 2000, gradually decreasing to 6 percent
by the year 2004. The rate of increase in per capita costs for covered health
care benefits was 8.4 percent and 9.0 percent in 1999 and 1998. A one-percentage
point change from assumed health care cost trend rates would have the following
effects:

<TABLE>
<CAPTION>
                                                              2000    1999
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
One Percentage Point Increase
  Aggregate of service cost and interest cost...............  $ --    $ --
  Accumulated postretirement benefit obligation.............  $  6    $  5
One Percentage Point Decrease
  Aggregate of service cost and interest cost...............  $ --    $ --
  Accumulated postretirement benefit obligation.............  $ (6)   $ (5)
</TABLE>

     Plan assets of the pension plan included our common stock and Class A
common stock, amounting to a total of 7.2 million of our shares at December 31,
2000 and 1999.

     We also participate in several multi-employer pension plans for the benefit
of our employees who are union members. Our contributions to these plans were
not material for 2000, 1999 or 1998.

     We also make contributions to a thrift plan, which is a trusteed, voluntary
and contributory plan for our eligible employees. We match 100 percent of
participant basic contributions up to 8 percent, with the matching contribution
being made in our stock. Our contributions, which are based on matching employee
contributions, amounted to $21 million, $20 million and $19 million in 2000,
1999 and 1998.

     In conjunction with the El Paso merger, some of our benefit plans will be
merged into comparable El Paso benefit plans, while other benefit plans will be
terminated.

10. SECURITIES OF SUBSIDIARIES

     Company-obligated Preferred Securities of a Consolidated Trust.  On May 13,
1998, we completed a public offering of 12,000,000 mandatory redemption
preferred securities through an affiliate, Coastal Finance I, a business trust,
for $300 million in cash. Coastal Finance I holds debt securities of ours
purchased with the proceeds of the preferred securities offering. Cumulative
quarterly distributions are being paid on the preferred securities at an annual
rate of 8.375% of the liquidation amount of $25 per preferred security. The
preferred securities are mandatorily redeemable on the maturity date, May 13,
2038, and may be redeemed at our option on or after May 13, 2003, or earlier if
various events occur. The redemption price to be paid is $25 per preferred
security, plus accrued and unpaid distributions to the date of redemption.

     Preferred Stock of Subsidiaries.  Coastal Securities Company Limited, our
wholly owned subsidiary, issued 4,000,000 shares of preferred stock in 1996 for
$100 million in cash. Quarterly cash dividends are being paid on the preferred
stock at a rate based on LIBOR. The preferred shareholders are also entitled to
participating dividends based on refining margins. Coastal Securities may redeem
the preferred stock on or after December 31, 1999 for cash.

     In 1999, Coastal Oil & Gas Resources, Inc., our wholly owned subsidiary,
issued 50,000 shares of preferred stock for $50 million in cash. The preferred
shareholders are entitled to quarterly cash dividends at a

                                        44
<PAGE>   47

rate based on LIBOR. The dividend rate is subject to renegotiation in 2004 and
on each fifth anniversary thereafter. In the event Coastal Oil & Gas and the
preferred shareholders are unable to agree to a new rate, Coastal Oil & Gas must
redeem the shares at $1,000 per share plus any accrued and unpaid dividends, or
cause the preferred stock to be registered with the Securities and Exchange
Commission and remarketed. Coastal Oil & Gas also has the option to redeem all
shares on any dividend rate reset date for $1,000 per share plus any accrued and
unpaid preferred dividends.

     In 1999, Coastal Limited Ventures, Inc., our wholly owned subsidiary,
issued 150,000 shares of preferred stock for $15 million in cash. The preferred
shareholders are entitled to quarterly cash dividends at an annual rate of 6%.
The dividend rate is subject to renegotiation in 2004 and on each fifth
anniversary thereafter. In the event Coastal Limited and the preferred
shareholders are unable to agree to a new rate, the preferred shareholders may
call for redemption of all of the preferred shares. The redemption price is $100
per share plus any accrued and unpaid preferred dividends thereon. Coastal
Limited also has the option to redeem all shares on any rate reset date for $100
per share plus any accrued and unpaid preferred dividends.

     Consolidated Joint Venture.  In December 1999, Coastal Limited contributed
assets to a limited partnership in exchange for a controlling general
partnership interest. Limited interests in the partnership were issued to
unaffiliated investors for $286 million in cash. The limited partners are
entitled to a cumulative priority return based on LIBOR. The return is subject
to renegotiation in 2004 and on each fifth anniversary thereafter. The
partnership has a maximum life of 20 years, but may be terminated sooner subject
to certain conditions, including failure to agree to a new rate. Coastal Limited
may terminate the partnership at any time by repayment of the limited partners'
outstanding capital plus any unpaid priority returns.

11. SEGMENT AND GEOGRAPHIC REPORTING

     We operate principally in the following lines of business: natural gas;
refining, marketing and chemicals; exploration and production; power and coal.
Separate management of each segment is required because each line of business is
subject to different production, marketing and technology strategies.

     Natural gas operations involve the production, purchase, gathering,
processing, transportation, storage, marketing and sale of natural gas,
principally to utilities, industrial customers and other pipelines, and include
the operation of natural gas liquids extraction plants. Sales are primarily made
to pipeline and distribution companies in most major areas of the United States.

     Refining, marketing and chemicals operations involve the purchase,
transportation and sale of refined products, crude oil, condensate and natural
gas liquids; the operation of refineries and chemical plants; the sale at retail
of gasoline, petroleum products and convenience items; petroleum product
terminaling and marketing of crude oil and refined products. Products from this
segment are sold to customers worldwide.

     Exploration and production operations involve the exploration, development
and production of natural gas, crude oil, condensate and natural gas liquids.
Sales are made to affiliated companies, industrial users, interstate pipelines
and distribution companies in the Rocky Mountain, central and southwest areas of
the United States and offshore Gulf of Mexico.

     Power operations involve the ownership of, participation in and operation
of power projects in the United States and internationally. Power is sold to
customers in the Northeast and Midwest United States, Colorado and
internationally, in Asia and Latin America.

     Coal operations include the mining, processing and marketing of coal from
our reserves and from other sources, and the brokering of coal for others. Sales
are made to utilities and industrial customers in the United States and to
export markets in Canada and Europe.

     Corporate and other operations include real estate activities and corporate
income and expense not allocated to the operating segments.

     The accounting policies of the individual segments are the same as those
described in Note 1. Since earnings on equity investments can be a significant
source of earnings in several of our segments, we evaluate segment performance
based on EBIT instead of operating income.

                                        45
<PAGE>   48

     Information related to our segments for the years ended December 31, 2000,
1999 and 1998 are as follows:

<TABLE>
<CAPTION>
                                                            2000      1999      1998
                                                           -------   -------   ------
                                                                 (IN MILLIONS)
<S>                                                        <C>       <C>       <C>
Operating Revenues From External Customers
  Natural gas............................................  $ 3,629   $ 1,244   $1,357
  Refining, marketing and chemicals......................   13,171     8,139    7,236
  Exploration and production.............................      763       556      437
  Power..................................................      167       128      121
  Coal...................................................      277       258      242
  Corporate and other....................................        7         6       11
                                                           -------   -------   ------
          Consolidated totals............................  $18,014   $10,331   $9,404
                                                           =======   =======   ======
Intersegment Revenues
  Natural gas............................................  $    14   $     3   $    2
  Refining, marketing and chemicals......................       25         2        2
  Exploration and production.............................      320        28       27
  Power..................................................       --        --       --
  Coal...................................................       --        --       --
  Corporate and other....................................        9         9       11
                                                           -------   -------   ------
          Consolidated totals............................  $   368   $    42   $   42
                                                           =======   =======   ======
Income (Loss) Before Interest, Income Taxes and Other
  Charges
  Natural gas............................................  $   660   $   574   $  594
  Refining, marketing and chemicals......................      260       228      244
  Exploration and production.............................      426       186      110
  Power..................................................      142        89       68
  Coal...................................................        3        16       17
  Corporate and other....................................     (115)      (65)     (66)
                                                           -------   -------   ------
          Consolidated totals............................  $ 1,376   $ 1,028   $  967
                                                           =======   =======   ======
Depreciation, Depletion and Amortization (Excluding
  Amortization of Goodwill)
  Natural gas............................................  $   124   $   129   $  119
  Refining, marketing and chemicals......................       89        74       78
  Exploration and production.............................      396       232      209
  Power..................................................       12         8        3
  Coal...................................................       23        17       15
  Corporate and other....................................        4         4        7
                                                           -------   -------   ------
          Consolidated totals............................  $   648   $   464   $  431
                                                           =======   =======   ======
Equity Income from Investments (Included in other income,
  net)
  Natural gas............................................  $   133   $    96   $   80
  Refining, marketing and chemicals......................       23        20        1
  Exploration and production.............................       --        --       --
  Power..................................................      109        74       43
  Coal...................................................       --        --       --
  Corporate and other....................................       --        --       --
                                                           -------   -------   ------
          Consolidated totals............................  $   265   $   190   $  124
                                                           =======   =======   ======
</TABLE>

                                        46
<PAGE>   49

<TABLE>
<CAPTION>
                                                            2000      1999      1998
                                                           -------   -------   ------
                                                                 (IN MILLIONS)
<S>                                                        <C>       <C>       <C>
Capital Expenditures
  Natural gas............................................  $   277   $   307   $  192
  Refining, marketing and chemicals......................      138       163      229
  Exploration and production.............................    1,575     1,080      935
  Power..................................................       37       153        2
  Coal...................................................       78        65       35
  Corporate and other....................................        7        13       11
                                                           -------   -------   ------
          Consolidated totals............................  $ 2,112   $ 1,781   $1,404
                                                           =======   =======   ======
</TABLE>

     Our assets and amount of investment in equity method investees by segment
as of December 31, 2000, 1999 and 1998 are as follows:

<TABLE>
<CAPTION>
                                                           2000      1999      1998
                                                          -------   -------   -------
                                                                 (IN MILLIONS)
<S>                                                       <C>       <C>       <C>
Assets
  Natural gas...........................................  $ 7,478   $ 5,801   $ 5,379
  Refining, marketing and chemicals.....................    4,662     4,464     3,351
  Exploration and production............................    4,381     3,030     2,162
  Power.................................................      968       765       450
  Coal..................................................      356       307       270
  Corporate and other...................................      724       756       692
                                                          -------   -------   -------
          Consolidated totals...........................  $18,569   $15,123   $12,304
                                                          =======   =======   =======
Equity Method Investments
  Natural gas...........................................  $   803   $   851   $   609
  Refining, marketing and chemicals.....................      124        99        68
  Exploration and production............................       --        --        --
  Power.................................................      652       486       295
  Coal..................................................        1         1         1
  Corporate and other...................................       16        (2)       (2)
                                                          -------   -------   -------
          Consolidated totals...........................  $ 1,596   $ 1,435   $   971
                                                          =======   =======   =======
</TABLE>

     Intersegment sales are accounted for on the basis of contract, current
market or internally established transfer prices.

     In October 2000, we and Westcoast Energy Inc. terminated the Engage joint
venture that had been formed in 1997. The operations were divided into separate
entities that are owned and operated independently by each company. Natural gas
operating revenues for the last three months of 2000 include revenues of $1,871
million from the Engage operations we now own and operate. Prior to the
termination, Engage's revenues are not included in our operating revenues;
however, our share of Engage's net earnings is included in Other income, net.

     In June 1998, the power purchase agreement associated with our Fulton Power
Plant was restructured. In connection with the restructuring, a net gain of $17
million was recorded in the Power segment. The net gain reflects a $23 million
reduction in the Plant's carrying value (to estimated fair value following the
restructuring) and deferral of some of the proceeds to cover estimated future
costs.

     In October 1998, we sold several non-core natural gas processing and
gathering assets. Revenues and earnings before interest and income taxes for the
Natural Gas segment include a gain of $59 million from the sale.

                                        47
<PAGE>   50

     Our operating revenues for the years ended December 31, 2000, 1999 and 1998
and property, plant and equipment as of December 31, 2000, 1999 and 1998, by
geographic area, are shown as follows:

<TABLE>
<CAPTION>
                                                            2000      1999      1998
                                                           -------   -------   ------
                                                                 (IN MILLIONS)
<S>                                                        <C>       <C>       <C>
Operating Revenues
  United States..........................................  $14,619   $ 8,370   $7,971
  Foreign, Aruba.........................................    3,064     1,674    1,190
  Foreign, Other.........................................      331       287      243
                                                           -------   -------   ------
          Consolidated totals............................  $18,014   $10,331   $9,404
                                                           =======   =======   ======
Property, Plant and Equipment
  United States..........................................  $ 9,775   $ 8,608   $7,345
  Foreign, Aruba.........................................      638       589      564
  Foreign, Other.........................................      225       140      115
                                                           -------   -------   ------
          Consolidated totals............................  $10,638   $ 9,337   $8,024
                                                           =======   =======   ======
</TABLE>

     Revenues from sales to any single customer during 2000, 1999 or 1998 did
not amount to 10 percent or more of our consolidated revenues. Revenues by
geographic area are attributed to countries based on the location of our
subsidiaries making the sales.

12. INVESTMENT IN AFFILIATED COMPANIES (UNAUDITED)

     We have interests in corporations and partnerships which are accounted for
on an equity basis. Several of the investments, included in Other Assets, are as
follows:

<TABLE>
<CAPTION>
                                                              PERCENTAGE
                     AFFILIATED COMPANY                       OWNERSHIP
                     ------------------                       ----------
<S>                                                           <C>
Great Lakes Gas Transmission Limited Partnership............      50%
Empire State Pipeline(1)....................................      50%
Eagle Point Cogeneration Partnership(2).....................      50%
Midland Cogeneration Venture Limited Partners...............      44%
Javelina Company............................................      40%
Iroquois Gas Transmission System, L.P.(1)...................      16%
Alliance Pipeline Limited Partnership.......................      14%
</TABLE>

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

(1) In connection with our merger with El Paso, we are required to divest our
    interests in Empire and Iroquois.

(2) Our interest in the Eagle Point Cogeneration Partnership increased from 50
    percent to 84 percent effective as of January 1, 2001.

     Our investment in these entities, including advances, totaled $1,596
million and $1,435 million at December 31, 2000 and 1999. Our equity in income
of the investments, included in Other income, net, was $265 million, $190
million and $124 million in 2000, 1999 and 1998, while dividends and partnership
distributions received amounted to $262 million, $151 million and $83 million in
2000, 1999 and 1998.

     Summarized financial information of these entities is as follows:

<TABLE>
<CAPTION>
                                                             YEAR ENDED DECEMBER 31,
                                                             ------------------------
                                                              2000     1999     1998
                                                             ------   ------   ------
                                                                  (IN MILLIONS)
<S>                                                          <C>      <C>      <C>
Operating results data:
  Revenues.................................................  $7,991   $7,271   $7,631
  Operating income.........................................     796      661      563
  Net income...............................................     546      495      307
</TABLE>

                                        48
<PAGE>   51

<TABLE>
<CAPTION>
                                                               DECEMBER 31,
                                                              ---------------
                                                               2000     1999
                                                              ------   ------
                                                               (IN MILLIONS)
<S>                                                           <C>      <C>
Financial position data:
  Current assets............................................  $1,661   $2,095
  Noncurrent assets.........................................   8,464    7,339
  Current liabilities.......................................   1,285    1,673
  Noncurrent liabilities....................................   4,622    4,089
  Deferred credits..........................................     266      456
  Equity....................................................   3,952    3,216
</TABLE>

13. DISCONTINUED OPERATIONS

     We are pursuing the disposition of our 50% ownership of ANR Advance
Transportation Company, Inc., a trucking operation. ANR Advance is being
liquidated in cooperation with other owners. Accordingly, the trucking
operations are being reported as a discontinued operation.

     The net assets being disposed of have been classified in the accompanying
consolidated balance sheets in Other Assets at December 31, 2000 and 1999. The
net assets of the discontinued operations amounted to $3 million at December 31,
2000 and 1999.

     Operating results of the discontinued operations are shown separately in
the accompanying consolidated statements of income. The loss from operations
shown on the consolidated statements of income is net of income tax benefits of
$2 million in 1998. The estimated loss on disposal of the discontinued
operations of $35 million is net of income tax benefits of $19 million.

14. INVENTORIES

     Inventories at December 31 were:

<TABLE>
<CAPTION>
                                                              2000     1999
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Refined products, crude oil and chemicals...................  $690     $576
Natural gas in underground storage..........................    14       --
Coal, materials and supplies................................   163      157
                                                              ----     ----
                                                              $867     $733
                                                              ====     ====
</TABLE>

     Material, labor and manufacturing expenses are included in inventory cost.

15. COMMITMENTS AND CONTINGENCIES

  Legal Proceedings

     In October 1992, several property owners in McAllen, Texas filed suit in
the 93rd Judicial District Court, Hidalgo County, Texas, against, among others,
one of our subsidiaries (Timely Adventures, Inc. et al, v. Phillips Properties,
Inc., et al and Garza v. Coastal Mart, Inc.). The suit sought damages for the
alleged diminution of property value and damages related to the exposure to
hazardous chemicals arising from the operation of service stations and storage
facilities. In July 2000, the trial court entered a judgment for approximately
$1.2 million in actual damages for property diminution and approximately $100
million in punitive damages. The judgment is being appealed.

     In October 1996, we, along with several subsidiaries, were named as
defendants in a suit filed by several former and current African American
employees in the U.S. District Court, Southern District of Texas. The suit
alleged racially discriminatory employment policies and practices. We vigorously
denied these allegations and filed responsive pleadings. Plaintiffs' counsel
sought to have the suit certified as a class action of all former and current
African American employees and initially claimed compensatory and punitive
damages of $400 million. In September 2000, we reached an agreement on terms
that would settle all individual and class claims. The court has given
preliminary approval to the settlement and has set the fairness hearing for May
11, 2001.

                                        49
<PAGE>   52

     In May 1999, we were named as defendants in a suit filed by an individual
employed by one of our contractors in the 319th Judicial District Court, Nueces
County, Texas (Rolando Lopez and Rosanna Barton v. Coastal Refining & Marketing,
Inc. and The Coastal Corporation). The suit sought damages for injuries
sustained at the time of an explosion at one of our refining plants, and was
settled in August 2000 for a total payment of $7 million, of which $5 million
was covered by insurance. Three of our refinery employees intervened in the suit
and sought damages for injuries sustained in the explosion. Those claims were
tried in August 2000, resulting in a $122 million verdict, which is also covered
by insurance and which is being appealed by the insurance carrier.

     In 1999, a number of our subsidiaries were named defendants in actions
brought by Jack Grynberg on behalf of the U.S. Government under the False Claims
Act. Generally, these complaints allege an industry-wide conspiracy to under
report the heating value as well as the volumes of the natural gas produced from
federal and Native American lands, which deprived the U.S. Government of
royalties. These matters have been consolidated for pretrial purposes. (In re:
Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District
of Wyoming.)

     A number of our subsidiaries are named defendants in an action styled
Quinque Operating Company, et al v. Gas Pipelines and Their Predecessors, et al,
filed in 1999 in the District Court of Stevens County, Kansas. This class action
complaint alleges that the defendants mismeasured natural gas volumes and
heating content of natural gas on non-federal and non-Native American lands. The
Quinque complaint, once transferred to the same court handling the Grynberg
complaint, has been sent back to the Kansas State Court for further proceedings.

     We are also a named defendant in numerous lawsuits and a named party in
numerous governmental proceedings arising in the ordinary course of our
business.

     While the outcome of the matters discussed above cannot be predicted with
certainty, we do not expect the ultimate resolution of these matters will have a
material adverse effect on our financial position, operating results, or cash
flows.

  Environmental

     Our operations are subject to extensive and evolving federal, state and
local environmental laws and regulations. Compliance with such laws and
regulations can be costly. Additionally, governmental authorities may enforce
the laws and regulations with a variety of civil and criminal enforcement
measures, including monetary penalties and remediation requirements.

     We spent approximately $16 million in 2000 on environmental capital
projects and anticipate capital expenditures of approximately $50 million in
2001 in order to comply with such laws and regulations. The majority of the 2000
expenditures is attributable to projects at our refining, chemical and
terminalling facilities. We currently anticipate capital expenditures for
environmental compliance of $30 million to $75 million per year over the next
several years.

     The Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA) imposes liability for the release of a hazardous substance into the
environment. CERCLA liability is imposed without regard to fault and even if the
waste disposal was in compliance with the then current laws and regulations.
With the joint and several liability imposed under CERCLA, a potentially
responsible party (PRP) may be required to pay more than its proportional share
of such costs. Several of our subsidiaries and a company in which we own a 50%
interest have been named as a PRP in various CERCLA waste disposal sites. At the
eight sites for which there is sufficient information, total cleanup costs are
estimated to be approximately $605 million. We estimate our pro-rata exposure,
to be paid over a period of years, is approximately $4 million, and we have made
appropriate provisions. At thirteen other sites, the EPA is currently unable to
provide us with an estimate of total cleanup costs, and accordingly, we are
unable to calculate our share of those costs.

                                        50
<PAGE>   53

     Additionally, several of our subsidiaries have been named as PRPs in four
state sites. In Florida, the Florida Department of Environmental Protection has
demanded reimbursement of its costs, which total approximately $300,000, and
suitable remediation, with approximately $100,000 potentially attributable to
our subsidiary's activities. In North Carolina, the North Carolina Department of
Health, Environmental and Natural Resources has estimated the total cleanup
costs to be approximately $50 million. In Texas, the Texas Natural Resource
Conservation Commission has estimated the total cleanup costs to be
approximately $2 million. In Utah, a remediation plan has been submitted to the
Utah Department of Environmental Quality for approval, with current estimated
cleanup costs of approximately $1.2 million attributable to our subsidiary's
activities. At all of the four state sites, we believe our subsidiaries'
activities were de minimis. With respect to the Texas site, we have entered into
a joint defense agreement with the other PRPs for the payment of $20,000 as a de
minimis settlement.

     From March to October 2000, our Eagle Point Oil Company received several
Administrative Order Notices of Civil Administrative Penalty Assessment from the
New Jersey Department of Environmental Protection. All of the assessments are
related to similar alleged noncompliances of the New Jersey Air Pollution
Control Act pertaining to occurrences of air pollution from the second quarter
1998 through the third quarter 2000 by Eagle Point's refinery in Westville, New
Jersey. The New Jersey Department of Environmental Protection has assessed
penalties totaling $1,188,000 for these alleged noncompliances. Eagle Point has
requested an administrative hearing on all issues raised by the assessments and
concurrently, is in negotiations to settle these assessments.

     It is possible that new information or future developments could require us
to reassess our potential exposure related to environmental matters. We may
incur significant costs and liabilities in order to comply with existing
environmental laws and regulations. It is also possible that other developments,
such as increasingly strict environmental laws and regulations, and claims for
damages to property, employees, other persons and the environment resulting from
our current or past operations, could result in substantial costs and
liabilities in the future. As this information becomes available, or other
relevant developments occur, we will adjust our accrual amounts accordingly.
While there are still uncertainties relating to the ultimate costs we may incur,
based upon our evaluation and experience to date, we believe that compliance
with all applicable laws and regulations will not have a material adverse impact
on our financial position, operating results or cash flows.

     Regulatory Matters.  Several regulatory issues remain unresolved among CIG,
ANR, ANR Storage and Wyoming Interstate, their customers, their suppliers and
FERC. We have made provisions which represent management's assessment of the
ultimate resolution of these issues. While we cannot predict with certainty the
final outcome or the timing of the resolution of all of our regulatory matters,
we believe the ultimate resolution of these issues will not have a material
adverse effect on our financial position, operating results, or cash flows.

  Leases and Commitments

     We lease property, plant and equipment under various operating leases, some
of which contain renewal and purchase options and residual value guarantees.
Such residual value guarantees amount to approximately $533 million. Rental
expense amounted to approximately $140 million, $120 million and $86 million in
2000, 1999 and 1998, excluding leases covering natural resources. Aggregate
minimum lease payments under existing noncapitalized long-term leases are
estimated to be $150 million, $139 million, $131 million, $130 million, and $125
million for the years 2001-2005 and $613 million thereafter.

                                        51
<PAGE>   54

16. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

     Financial information by quarter is summarized below. In the opinion of
management, all adjustments necessary for a fair presentation have been made.

<TABLE>
<CAPTION>
                                                                  QUARTERS ENDED
                                                ---------------------------------------------------
                                                MARCH 31    JUNE 30    SEPTEMBER 30    DECEMBER 31
                                                ---------   --------   -------------   ------------
                                                      (IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
<S>                                             <C>         <C>        <C>             <C>
2000
  Operating revenues..........................   $3,597      $3,992       $4,366          $6,059
  Less purchases..............................    2,674       3,085        3,421           4,954
                                                 ------      ------       ------          ------
                                                    923         907          945           1,105
  Other income and expenses...................      750         779          800             897
                                                 ------      ------       ------          ------
  Net income..................................   $  173      $  128       $  145          $  208
                                                 ======      ======       ======          ======
  Basic earnings per share....................   $  .81      $  .60       $  .67          $  .97
                                                 ======      ======       ======          ======
  Diluted earnings per share..................   $  .80      $  .58       $  .65          $  .93
                                                 ======      ======       ======          ======
</TABLE>

<TABLE>
<CAPTION>
                                                                  QUARTERS ENDED
                                                ---------------------------------------------------
                                                MARCH 31    JUNE 30    SEPTEMBER 30    DECEMBER 31
                                                ---------   --------   -------------   ------------
                                                      (IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
<S>                                             <C>         <C>        <C>             <C>
1999
  Operating revenues..........................   $2,172      $2,356       $2,562          $3,241
  Less purchases..............................    1,408       1,648        1,797           2,429
                                                 ------      ------       ------          ------
                                                    764         708          765             812
  Other income and expenses...................      629         615          663             643
                                                 ------      ------       ------          ------
  Net income..................................   $  135      $   93       $  102          $  169
                                                 ======      ======       ======          ======
  Basic earnings per share....................   $  .63      $  .44       $  .48          $  .79
                                                 ======      ======       ======          ======
  Diluted earnings per share..................   $  .62      $  .43       $  .47          $  .78
                                                 ======      ======       ======          ======
</TABLE>

     In 2000, we applied FASB Emerging Issues Task Force Issue No. 99-19,
Reporting Revenue Gross as a Principal versus Net as an Agent, which resulted in
the reclassification of revenues and purchases for various trading and marketing
activities that had been previously reported on a net basis. This change had no
impact on gross margins or net income. All quarterly amounts have been
reclassified to conform with the new presentation.

17. SUPPLEMENTAL NATURAL GAS AND OIL OPERATIONS (UNAUDITED)

     Reserves; capitalized costs; costs incurred in oil and gas acquisition,
exploration and development activities; results of operations; and the
standardized measure of discounted future net cash flows are presented for the
exploration and production segment. Natural gas systems reserves and the related
standardized measure of discounted future net cash flows are separately
presented for natural gas systems operations. All of our proved properties, with
the exception of the proved reserves in Brazil noted below, are located in North
America (U.S. and Canada). The following reserve tables report on U.S.
operations and do not include approximately 190,000 MMcfe of Canadian proved
reserves with 1,139 MMcfe of Canadian production during 2000 and 120,000 MMcfe
of Brazilian proved reserves.

                                        52
<PAGE>   55

Estimated Quantities of Proved Reserves (Domestic)

<TABLE>
<CAPTION>
                                                  NATURAL GAS
                                                    SYSTEMS     EXPLORATION AND PRODUCTION
                                                  -----------   ---------------------------
                                                   DEVELOPED     DEVELOPED     UNDEVELOPED      TOTAL
                                                  -----------   -----------   -------------   ---------
<S>                                               <C>           <C>           <C>             <C>
Natural Gas (MMcf):
  2000..........................................    175,353      1,815,562      2,204,768     4,195,683
  1999..........................................    197,649      1,625,713      1,643,350     3,466,712
  1998..........................................    211,761      1,287,207      1,028,167     2,527,135
Oil, Condensate and Natural Gas Liquids (MBbls):
  2000..........................................        231         36,404         28,403        65,038
  1999..........................................        249         33,690         23,188        57,127
  1998..........................................        237         31,894         20,153        52,284
</TABLE>

     Changes in proved reserves since the end of 1997 are shown in the following
table.

<TABLE>
<CAPTION>
                                                                                OIL, CONDENSATE AND
                                                            NATURAL GAS         NATURAL GAS LIQUIDS
                                                       ---------------------   ---------------------
                                                       NATURAL   EXPLORATION   NATURAL   EXPLORATION
                                                         GAS         AND         GAS         AND
                                                       SYSTEMS   PRODUCTION    SYSTEMS   PRODUCTION
                                                       -------   -----------   -------   -----------
                                                              (MMCF)                  (MBBLS)
<S>                                                    <C>       <C>           <C>       <C>
Total Proved Reserves
  Total, end of 1997.................................  248,248    1,504,266      349       39,794
  Production during 1998.............................  (39,058)    (185,732)     (44)      (5,578)
  Extensions and discoveries.........................      404      518,529       --        9,185
  Acquisitions.......................................       --      575,934       --       11,915
  Sales of reserves in-place.........................       --      (25,556)      --       (1,072)
  Revisions of previous quantity estimates and
     other...........................................    2,167      (72,067)     (68)      (2,197)
                                                       -------    ---------      ---       ------
          Total, end of 1998.........................  211,761    2,315,374      237       52,047
                                                       -------    ---------      ---       ------
  Production during 1999.............................  (35,634)    (230,542)     (24)      (4,475)
  Extensions and discoveries.........................       --      745,565       --        5,354
  Acquisitions.......................................       --      539,274       --       11,377
  Sales of reserves in-place.........................       --      (39,908)      --         (805)
  Revisions of previous quantity estimates and
     other...........................................   21,522      (60,700)      36       (6,620)
                                                       -------    ---------      ---       ------
          Total, end of 1999.........................  197,649    3,269,063      249       56,878
                                                       -------    ---------      ---       ------
  Production during 2000.............................  (33,433)    (328,007)     (25)      (6,477)
  Extensions and discoveries.........................       --      802,366       --        8,231
  Acquisitions.......................................       --      498,701       --        6,546
  Sales of reserves in-place.........................       --      (18,770)      --         (609)
  Revisions of previous quantity estimates and
     other...........................................   11,137     (203,023)       7          238
                                                       -------    ---------      ---       ------
          Total, end of 2000.........................  175,353    4,020,330      231       64,807
                                                       =======    =========      ===       ======
</TABLE>

     Total proved reserves for natural gas systems exclude storage gas and
liquids volumes. The natural gas systems storage gas volumes are 199,937 MMcf,
221,509 MMcf, and 225,853 MMcf and storage liquids volumes are approximately 237
MBbls, 301 MBbls, and 232 MBbls at December 31, 2000, 1999 and 1998. Total
proved reserves for natural gas equivalents include approximately 130,000 MMcf,
152,000 MMcf, and 162,000 MMcf associated with volumetric production payments we
sold to unaffiliated entities for the years 2000, 1999 and 1998.

     All of our proved reserves, with the exception of the Brazilian reserves
noted earlier, are located in North America (U.S. and Canada). Other
international activities are connected with the evaluation of various
concessions, which are periodically reviewed for impairment.

                                        53
<PAGE>   56

Capitalized Costs Relating to Exploration and Production Activities

<TABLE>
<CAPTION>
                                                                DECEMBER 31,
                                                              ----------------
                                                               2000      1999
                                                              ------    ------
                                                               (IN MILLIONS)
<S>                                                           <C>       <C>
Proved and Unproved Properties:
  Proved properties.........................................  $4,281    $3,234
  Unproved properties.......................................     747       536
                                                              ------    ------
                                                               5,028     3,770
  Accumulated depreciation, depletion and amortization......    (987)     (904)
                                                              ------    ------
                                                              $4,041    $2,866
                                                              ======    ======
</TABLE>

                        COSTS EXCLUDED FROM AMORTIZATION

     The following table summarizes the costs related to unevaluated properties
and major development projects that are excluded from amounts subject to
amortization at December 31, 2000. We regularly evaluate these costs to
determine whether impairment has occurred. The majority of these costs are
expected to be evaluated and included in the amortization base within three
years.

<TABLE>
<CAPTION>
                                                                  YEARS COSTS INCURRED
                                                          -------------------------------------
                                                                                       PRIOR TO
                                                          TOTAL   2000   1999   1998     1998
                                                          -----   ----   ----   ----   --------
                                                                      (IN MILLIONS)
<S>                                                       <C>     <C>    <C>    <C>    <C>
Property acquisition....................................  $370    $129   $114   $114     $13
Exploration.............................................   213     133     36     32      12
Development.............................................   114      55     33     19       7
Capitalized interest....................................    50      38     12     --      --
                                                          ----    ----   ----   ----     ---
                                                          $747    $355   $195   $165     $32
                                                          ====    ====   ====   ====     ===
</TABLE>

Costs Incurred in Oil and Gas Acquisition, Exploration and Development
Activities

<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31,
                                                              -----------------------
                                                               2000     1999    1998
                                                              -------   -----   -----
                                                                   (IN MILLIONS)
<S>                                                           <C>       <C>     <C>
Property acquisition costs
  Proved....................................................  $  130    $154    $129
  Unproved..................................................     136     152     133
Exploration costs...........................................     267     168     123
Development costs...........................................   1,029     593     540
</TABLE>

Results of Operations for Exploration and Production Activities

<TABLE>
<CAPTION>
                                                               YEAR ENDED DECEMBER 31,
                                                              -------------------------
                                                               2000      1999     1998
                                                              -------   ------   ------
                                                                    (IN MILLIONS)
<S>                                                           <C>       <C>      <C>
Revenues:
  Sales.....................................................  $  870    $ 451    $ 333
  Transfers.................................................     216      113      111
                                                              ------    -----    -----
  Total.....................................................   1,086      564      444
                                                              ------    -----    -----
Production costs............................................    (166)    (104)     (89)
Operating expenses..........................................     (75)     (51)     (44)
Depreciation, depletion and amortization....................    (388)    (233)    (204)
                                                              ------    -----    -----
                                                                 457      176      107
Income tax expense..........................................    (154)     (56)     (29)
                                                              ------    -----    -----
Results of operations for producing activities (excluding
  corporate overhead and interest costs)....................  $  303    $ 120    $  78
                                                              ======    =====    =====
</TABLE>

                                        54
<PAGE>   57

     The average domestic amortization rate per Mcfe was $1.015 in 2000, $0.87
in 1999 and $0.89 in 1998.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserve Quantities

     Future cash inflows for the years ended December 31, 2000, 1999 and 1998
from the sale of proved reserves and estimated production and development costs
as calculated by our engineers and reviewed by Huddleston & Co., Inc., our
independent engineers, are discounted by 10% after they are reduced by our
estimate for future income taxes. The calculations are based on year-end prices
and costs, statutory tax rates and nonconventional fuel source tax credits that
relate to existing proved oil and gas reserves in which we have mineral
interests.

     The standardized measure is not intended to represent the market value of
reserves and, in view of the uncertainties involved in the reserve estimation
process, including the instability of energy markets as evidenced by changes in
both natural gas and crude oil prices, may be subject to material future
revisions:

<TABLE>
<CAPTION>
                                                                   YEAR ENDED DECEMBER 31,
                                  ------------------------------------------------------------------------------------------
                                              2000                           1999                           1998
                                  ----------------------------   ----------------------------   ----------------------------
                                  NATURAL GAS    EXPLORATION     NATURAL GAS    EXPLORATION     NATURAL GAS    EXPLORATION
                                    SYSTEMS     AND PRODUCTION     SYSTEMS     AND PRODUCTION     SYSTEMS     AND PRODUCTION
                                  -----------   --------------   -----------   --------------   -----------   --------------
                                                                        (IN MILLIONS)
<S>                               <C>           <C>              <C>           <C>              <C>           <C>
Future cash inflows.............     $ 474         $30,059          $229          $ 8,404          $256          $ 4,939
Future production and
  development costs.............      (110)         (5,974)          (74)          (2,768)          (79)          (1,909)
Future income tax expenses......      (116)         (7,677)          (49)          (1,299)          (57)            (584)
                                     -----         -------          ----          -------          ----          -------
Future net cash flows...........       248          16,408           106            4,337           120            2,446
10% annual discount for
  estimated timing of cash
  flows.........................       (89)         (7,063)          (41)          (1,556)          (51)            (865)
                                     -----         -------          ----          -------          ----          -------
Standardized measure of
  discounted future net cash
  flows.........................     $ 159         $ 9,345          $ 65          $ 2,781          $ 69          $ 1,581
                                     =====         =======          ====          =======          ====          =======
</TABLE>

     Future net cash flows include approximately $486 million for 2000, $190
million for 1999 and $156 million for 1998 related to volumes dedicated to
volumetric production payments that we sold to unaffiliated entities.

     Principal sources of change in the standardized measure of discounted
future net cash flows during each year are:

<TABLE>
<CAPTION>
                                                                   YEAR ENDED DECEMBER 31,
                                  ------------------------------------------------------------------------------------------
                                              2000                           1999                           1998
                                  ----------------------------   ----------------------------   ----------------------------
                                  NATURAL GAS    EXPLORATION     NATURAL GAS    EXPLORATION     NATURAL GAS    EXPLORATION
                                    SYSTEMS     AND PRODUCTION     SYSTEMS     AND PRODUCTION     SYSTEMS     AND PRODUCTION
                                  -----------   --------------   -----------   --------------   -----------   --------------
                                                                        (IN MILLIONS)
<S>                               <C>           <C>              <C>           <C>              <C>           <C>
Sales and transfers, net of
  production costs..............     $(52)         $(1,299)         $(36)          $ (474)         $(34)          $(338)
Net changes in prices and
  production costs..............      150            6,934            (6)             734             3            (334)
Extensions and discoveries......       --            3,589            --              634            --             430
Acquisitions....................       --            1,296            --              643            --             317
Sales of reserves in-place......       --              (14)           --              (33)           --             (21)
Development costs incurred
  during the period that reduced
  estimated future development
  costs.........................       --               89            --              102            --             115
Revisions of previous quantity
  estimates, timing and other...       34             (924)           28             (235)            6            (322)
Accretion of discount...........        4              196             7              136             8             141
Net change in income taxes......      (42)          (3,303)            3             (307)            6             168
                                     ----          -------          ----           ------          ----           -----
Net change......................     $ 94          $ 6,564          $ (4)          $1,200          $(11)          $ 156
                                     ====          =======          ====           ======          ====           =====
</TABLE>

     None of the amounts include any value for natural gas systems storage gas
and liquids volumes, which was approximately 39 Bcf for CIG, 107 Bcf for ANR, 54
Bcf for Mid Michigan Gas Storage Company and 237 MBbls of liquids for CIG at the
end of 2000.

                                        55
<PAGE>   58

                          INDEPENDENT AUDITORS' REPORT

Board of Directors and Stockholders
El Paso CGP Company
Houston, Texas

     We have audited the accompanying consolidated balance sheets of El Paso CGP
Company (formerly The Coastal Corporation) and subsidiaries as of December 31,
2000 and 1999, and the related consolidated statements of income, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 2000. Our audits also included the financial statement schedule listed in
the Index at Item 14(a)2. These financial statements and financial statement
schedule are the responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements and financial statement
schedule based on our audits.

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

     In our opinion, such consolidated financial statements present fairly, in
all material respects, the consolidated financial position of El Paso CGP
Company and subsidiaries as of December 31, 2000 and 1999, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2000, in conformity with accounting principles generally
accepted in the United States of America. Also, in our opinion, such financial
statement schedule, when considered in relation to the basic consolidated
financial statements taken as a whole, presents fairly in all material respects
the information set forth therein.

DELOITTE & TOUCHE LLP

Houston, Texas
March 19, 2001

                                        56
<PAGE>   59

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

     None.

                                    PART III

     Item 10, "Directors and Executive Officers of the Registrant;" Item 11,
"Executive Compensation;" Item 12, "Security Ownership of Management;" and Item
13, "Certain Relationships and Related Transactions," have been omitted from
this report pursuant to the reduced disclosure format permitted by General
Instruction I to Form 10-K.

                                    PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.

     (a) The following documents are filed as part of this Annual Report or
incorporated herein by reference:

          1. Financial statements.

             The following consolidated financial statements of El Paso CGP are
        included in Part II, Item 8 on this report:

<TABLE>
<CAPTION>
                                                              PAGE
                                                              ----
<S>                                                           <C>
Consolidated Statements of Income...........................    27
Consolidated Balance Sheets.................................    28
Consolidated Statements of Cash Flows.......................    29
Consolidated Statements of Stockholders' Equity.............    30
Notes to Consolidated Financial Statements..................    31
Independent Auditors' Report................................    57
</TABLE>

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

<TABLE>
<CAPTION>
                                                               PAGE
                                                               ----
<S>                                                            <C>
Schedule II  -- Valuation and Qualifying Accounts...........    61
</TABLE>

     Schedules other than those listed above are omitted because they are not
applicable.

                                        57
<PAGE>   60

          3. Exhibits.

     Each exhibit identified below is filed as a part of this report. Exhibits
not incorporated by reference to a prior filing are designated by an asterisk;
all exhibits not so designated are incorporated herein by reference to a prior
filing as indicated. Exhibits designated with a "+" constitute a management
contract or compensatory plan or arrangement required to be filed as an exhibit
to this report pursuant to Item 14(c) of Form 10-K.

<TABLE>
<CAPTION>
EXHIBIT NO.                                      DESCRIPTION
-----------                                      -----------
<C>                      <S>
           *3.A          -- Amended and Restated Certificate of Incorporation of El
                            Paso CGP Company as filed with the Delaware Secretary of
                            State on January 31, 2001.
           *3.B          -- By-Laws of El Paso CGP Company dated January 29, 2001.
           10.A          -- Replacement Pension Plan, effective as of November 1,
                            1987 (Exhibit 10.6 to El Paso CGP's 1987 Form 10-K).
           10.B          -- Pension Plan for Employees restated as of January 1,
                            1989, First Amendment dated July 27, 1992, Second
                            Amendment dated December 9, 1992, Third Amendment dated
                            October 29, 1993 (Exhibit 10.16 to El Paso CGP's 1993
                            Form 10-K); Fourth Amendment dated May 20, 1994, Fifth
                            Amendment dated August 17, 1994, Sixth Amendment dated
                            August 30, 1994, Seventh Amendment dated October 30,
                            1995, Eighth Amendment dated December 29, 1995 and Ninth
                            Amendment dated December 29, 1995 (Exhibit 10.14 to El
                            Paso CGP's 1995 Form 10-K); Tenth Amendment dated March
                            25, 1996 (Exhibit 10.15 to El Paso CGP's Form 10-Q for
                            the period ended March 31, 1996); Eleventh Amendment
                            dated December 6, 1996 (Exhibit 10.17 to El Paso CGP's
                            1996 Form 10-K); Twelfth Amendment dated August 29, 1996
                            and the Thirteenth Amendment dated September 16, 1996
                            (Exhibit 10.16 to El Paso CGP's Form 10-Q for the period
                            ended September 30, 1996); Fourteenth Amendment dated
                            December 31, 1997 (Exhibit 10.18 to El Paso CGP's 1997
                            Form 10-K).
          *10.C          -- Fifteenth Amendment dated September 29, 2000 to the
                            Pension Plan restated as of January 1, 1989.
          +10.D          -- Form of Employment Agreement between El Paso CGP and Gene
                            T. Waguespack, dated January 17, 2000 (Exhibit 10.21 to
                            El Paso CGP's 1999 Form 10-K); Form of Employment
                            Agreement between El Paso CGP and each of Rodney D.
                            Erskine, Dan J. Hill, and Thomas M. Wade, dated January
                            17, 2000 (Exhibit 10.22 to El Paso CGP's 1999 Form 10-K).
          +10.E          -- Agreement for Consulting Services between El Paso CGP and
                            Oscar S. Wyatt, Jr. dated August 1, 1997 (Exhibit 10.19
                            to El Paso CGP's 1997 Form 10-K).
          *10.F          -- $2,000,000 364-Day Revolving Credit and Competitive
                            Advance Facility Agreement dated as of August 2, 2000, by
                            and among El Paso, EPNG, TGP, the several banks and other
                            financial institutions from time to time parties to the
                            Agreement, The Chase Manhattan Bank, Citibank N.A. and
                            ABN Amro Bank, N.V. as co-documentation agents for the
                            Lenders and Bank of America, N.A. as syndication agent
                            for the Lenders.
          *10.G          -- $1,000,000,000 3-Year Revolving Credit and Competitive
                            Advance Facility Agreement dated as of August 4, 2000, by
                            and among El Paso EPNG, TGP, the several banks and other
                            financial institutions from time to time parties to the
                            Agreement, The Chase Manhattan Bank, Citibank N.A. and
                            ABN Amro Bank, N.V. as co-documentation agents for the
                            Lenders and Bank of America, N.A. as syndication agent
                            for the Lenders.
</TABLE>

                                        58
<PAGE>   61

<TABLE>
<CAPTION>
EXHIBIT NO.                                      DESCRIPTION
-----------                                      -----------
<C>                      <S>
          *10.H          -- Joinder Agreement dated February 5, 2001 made by El Paso
                            CGP Company to the $2,000,000,000 364-Day Revolving
                            Credit and CAF Advance Facility Agreement and the
                            $1,000,000,000 3-Year Revolving Credit and CAF Advance
                            Facility Agreement by and among El Paso, EPNG, TGP, the
                            several banks and other financial institutions from time
                            to time parties to the Agreement, The Chase Manhattan
                            Bank, as Administrative Agent and CAF Advance Agent,
                            Citibank, N.A. and ABN Amro, N.V. as Co-Documentation
                            Agents, and Bank of America, N.A. as syndication agent
                            for the Lenders.
          *23.1          -- Independent Auditors' Consent
          *23.2          -- Consent of Huddleston & Co., Inc.
</TABLE>

     (b) Reports on Form 8-K:

          We filed a Current Report on Form 8-K dated February 2, 2001,
     announcing that we became a direct subsidiary of El Paso Corporation as a
     result of our merger with a wholly owned subsidiary of El Paso Corporation
     on January 29, 2001.

                                        59
<PAGE>   62

                                   SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, as amended, El Paso CGP Company has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized
on the 23rd day of March 2001.

                                        EL PASO CGP COMPANY
                                        (Registrant)

                                        By:         /s/  WILLIAM A. WISE
                                           -------------------------------------
                                                      William A. Wise
                                           Chairman of the Board, President and
                                                  Chief Executive Officer

     Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, this report has been signed below by the following persons on behalf of
El Paso CGP Company and in the capacities and on the dates indicated:

<TABLE>
<CAPTION>
                       NAME                                        TITLE                     DATE
                       ----                                        -----                     ----
<C>                                                  <S>                                <C>

              By: /s/ WILLIAM A. WISE                Chairman of the Board, President,  March 23, 2001
  ----------------------------------------------       Chief Executive Officer and
                 (William A. Wise)                     Director

              By: /s/ H. BRENT AUSTIN                Executive Vice President, Chief    March 23, 2001
  ----------------------------------------------       Financial Officer and Director
                 (H. Brent Austin)

             By: /s/ JEFFREY I. BEASON               Senior Vice President and          March 23, 2001
  ----------------------------------------------       Controller (Chief Accounting
                (Jeffrey I. Beason)                    Officer)
</TABLE>

                                        60
<PAGE>   63

                                  SCHEDULE II

                      EL PASO CGP COMPANY AND SUBSIDIARIES

                       VALUATION AND QUALIFYING ACCOUNTS
                  YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
                                 (IN MILLIONS)

<TABLE>
<CAPTION>
                                                               CHARGED TO
                                                  BALANCE AT   COSTS AND                      BALANCE
                                                  BEGINNING     EXPENSES                      AT END
                  DESCRIPTION                     OF PERIOD    AND OTHER    DEDUCTIONS       OF PERIOD
                  -----------                     ----------   ----------   ----------       ---------
<S>                                               <C>          <C>          <C>              <C>
2000
Allowance for doubtful accounts.................     $17          $ 3          $(9)(1)          $11
Allowance for price risk management
  activities....................................      --           17(2)        --               17
1999
Allowance for doubtful accounts.................     $16          $ 4          $(3)(1)          $17
1998
Allowance for doubtful accounts.................     $17          $ 4          $(5)(1)          $16
</TABLE>

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

(1) Primarily accounts written off.

(2) Includes beginning balance of $16 million at October 1, 2000 for Coastal
Merchant Energy.

                                        61
<PAGE>   64

                               INDEX TO EXHIBITS

     Each exhibit identified below is filed as a part of this report. Exhibits
not incorporated by reference to a prior filing are designated by an asterisk;
all exhibits not so designated are incorporated herein by reference to a prior
filing as indicated. Exhibits designated with a "+" constitute a management
contract or compensatory plan or arrangement required to be filed as an exhibit
to this report pursuant to Item 14(c) of Form 10-K.

<TABLE>
<CAPTION>
EXHIBIT NO.                                      DESCRIPTION
-----------                                      -----------
<C>                      <S>
           *3.A          -- Amended and Restated Certificate of Incorporation of El
                            Paso CGP Company as filed with the Delaware Secretary of
                            State on January 31, 2001.
           *3.B          -- By-Laws of El Paso CGP Company dated January 29, 2001.
           10.A          -- Replacement Pension Plan, effective as of November 1,
                            1987 (Exhibit 10.6 to El Paso CGP's 1987 Form 10-K).
           10.B          -- Pension Plan for Employees restated as of January 1,
                            1989, First Amendment dated July 27, 1992, Second
                            Amendment dated December 9, 1992, Third Amendment dated
                            October 29, 1993 (Exhibit 10.16 to El Paso CGP's 1993
                            Form 10-K); Fourth Amendment dated May 20, 1994, Fifth
                            Amendment dated August 17, 1994, Sixth Amendment dated
                            August 30, 1994, Seventh Amendment dated October 30,
                            1995, Eighth Amendment dated December 29, 1995 and Ninth
                            Amendment dated December 29, 1995 (Exhibit 10.14 to El
                            Paso CGP's 1995 Form 10-K); Tenth Amendment dated March
                            25, 1996 (Exhibit 10.15 to El Paso CGP's Form 10-Q for
                            the period ended March 31, 1996); Eleventh Amendment
                            dated December 6, 1996 (Exhibit 10.17 to El Paso CGP's
                            1996 Form 10-K); Twelfth Amendment dated August 29, 1996
                            and the Thirteenth Amendment dated September 16, 1996
                            (Exhibit 10.16 to El Paso CGP's Form 10-Q for the period
                            ended September 30, 1996); Fourteenth Amendment dated
                            December 31, 1997 (Exhibit 10.18 to El Paso CGP's 1997
                            Form 10-K).
          *10.C          -- Fifteenth Amendment dated September 29, 2000 to the
                            Pension Plan restated as of January 1, 1989.
          +10.D          -- Form of Employment Agreement between El Paso CGP and Gene
                            T. Waguespack, dated January 17, 2000 (Exhibit 10.21 to
                            El Paso CGP's 1999 Form 10-K); Form of Employment
                            Agreement between El Paso CGP and each of Rodney D.
                            Erskine, Dan J. Hill, and Thomas M. Wade, dated January
                            17, 2000 (Exhibit 10.22 to El Paso CGP's 1999 Form 10-K).
          +10.E          -- Agreement for Consulting Services between El Paso CGP and
                            Oscar S. Wyatt, Jr. dated August 1, 1997 (Exhibit 10.19
                            to El Paso CGP's 1997 Form 10-K).
           10.F          -- $2,000,000 364-Day Revolving Credit and Competitive
                            Advance Facility Agreement dated as of August 2, 2000, by
                            and among El Paso, EPNG, TGP, the several banks and other
                            financial institutions from time to time parties to the
                            Agreement, The Chase Manhattan Bank, Citibank N.A. and
                            ABN Amro Bank, N.V. as co-documentation agents for the
                            Lenders and Bank of America, N.A. as syndication agent
                            for the Lenders.
          *10.G          -- $1,000,000,000 3-Year Revolving Credit and Competitive
                            Advance Facility Agreement dated as of August 4, 2000, by
                            and among El Paso EPNG, TGP, the several banks and other
                            financial institutions from time to time parties to the
                            Agreement, The Chase Manhattan Bank, Citibank N.A. and
                            ABN Amro Bank, N.V. as co-documentation agents for the
                            Lenders and Bank of America, N.A. as syndication agent
                            for the Lenders.
</TABLE>
<PAGE>   65

<TABLE>
<CAPTION>
EXHIBIT NO.                                      DESCRIPTION
-----------                                      -----------
<C>                      <S>
          *10.H          -- Joinder Agreement dated February 5, 2001 made by El Paso
                            CGP Company to the $2,000,000,000 364-Day Revolving
                            Credit and CAF Advance Facility Agreement and the
                            $1,000,000,000 3-Year Revolving Credit and CAF Advance
                            Facility Agreement by and among El Paso, EPNG, TGP, the
                            several banks and other financial institutions from time
                            to time parties to the Agreement, The Chase Manhattan
                            Bank, as Administrative Agent and CAF Advance Agent,
                            Citibank, N.A. and ABN Amro, N.V. as Co-Documentation
                            Agents, and Bank of America, N.A. as syndication agent
                            for the Lenders.
          *23.1          -- Independent Auditors' Consent
          *23.2          -- Consent of Huddleston & Co., Inc.
</TABLE>