<PAGE>   1
 
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                                 UNITED STATES
                       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, 1998
 
                                       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 1-9864
 
                         EL PASO TENNESSEE PIPELINE CO.
             (Exact name of registrant as specified in its charter)
 
<TABLE>
<S>                                                 <C>
                     DELAWARE                                           76-0233548
         (State or other jurisdiction of                             (I.R.S. Employer
          incorporation or organization)                           Identification No.)
 
             EL PASO ENERGY 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 1/4% Cumulative Preferred Stock, Series A.................   New York Stock Exchange
</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 (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X]  No [ ]
 
     Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.  [X]
 
     STATE THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES
OF THE REGISTRANT. Aggregate market value shall be computed by reference to the
price at which the stock was sold, or the average bid and asked prices of such
stock, as of the specified date within 60 days prior to the date of filing.
 
<TABLE>
<CAPTION>
                                                                  MARKET VALUE
         CLASS OF VOTING STOCK AND NUMBER OF SHARES                   HELD
          HELD BY NON-AFFILIATES AT MARCH 16, 1998              BY NON-AFFILIATES
          ----------------------------------------              -----------------
<S>                                                             <C>
8 1/4% Cumulative Preferred Stock, Series A, 6,000,000
  shares                                                          $328,125,000*
</TABLE>
 
---------------
 
*  Based upon the closing price on the Composite Tape for the 8 1/4% Cumulative
   Preferred Stock, Series A, on March 16, 1999.
 
     INDICATE THE NUMBER OF SHARES OUTSTANDING OF EACH OF THE REGISTRANT'S
CLASSES OF COMMON STOCK, AS OF THE LATEST PRACTICABLE DATE.
 
     Common Stock, par value $.01 per share. Shares outstanding on March 16,
1999: 1,971
 
                      DOCUMENTS INCORPORATED BY REFERENCE
 
     List hereunder the following documents if incorporated by reference and the
part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is
incorporated: El Paso Tennessee Pipeline Co.'s definitive Proxy Statement for
the 1999 Annual Meeting of Stockholders, to be filed not later than 120 days
after the end of the fiscal year covered by this report, is incorporated by
reference into Part III.
 
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<PAGE>   2
 
                         EL PASO TENNESSEE PIPELINE CO.
 
                               TABLE OF CONTENTS
 
<TABLE>
<CAPTION>
                                     CAPTION                             PAGE
                                     -------                             ----
<S>        <C>                                                           <C>
Glossary...............................................................   ii
 
                                      PART I
Item 1.    Business....................................................    1
Item 2.    Properties..................................................   10
Item 3.    Legal Proceedings...........................................   10
Item 4.    Submission of Matters to a Vote of Security Holders.........   10
 
                                     PART II
Item 5.    Market for Registrant's Common Equity and Related
             Stockholder Matters.......................................   11
Item 6.    Selected Financial Data.....................................   12
Item 7.    Management's Discussion and Analysis of Financial Condition
             and Results of Operations.................................   13
           Risk Factors -- Cautionary Statement for Purposes of the
             "Safe Harbor" Provisions of the Private Securities
             Litigation Reform Act of 1995.............................   29
Item 7A.   Quantitative and Qualitative Disclosures About Market
             Risk......................................................   32
Item 8.    Financial Statements and Supplementary Data.................   34
Item 9.    Changes in and Disagreements with Accountants on Accounting
             and Financial Disclosure..................................   62
 
                                     PART III
Item 10.   Directors and Executive Officers of the Registrant..........   62
Item 11.   Executive Compensation......................................   62
Item 12.   Security Ownership of Certain Beneficial Owners and
             Management................................................   62
Item 13.   Certain Relationships and Related Transactions..............   62
 
                                     PART IV
Item 14.   Exhibits, Financial Statement Schedules and Reports on Form
             8-K.......................................................   63
           Signatures..................................................   66
</TABLE>
 
                                        i
<PAGE>   3
 
                                    GLOSSARY
 
     The following abbreviations, acronyms, or defined terms used in this Form
10-K are defined below:
 
<TABLE>
<CAPTION>
                                                                DEFINITION
                                                                ----------
<S>                                 <C>
ALJ...............................  Administrative Law Judge
BBtu(/d)..........................  Billion British thermal units (per day)
Bcf(/d)...........................  Billion cubic feet (per day)
CAPSA.............................  Companias Asociadas Petroleras SA, a privately held integrated
                                    energy company in Argentina
Company...........................  El Paso Tennessee Pipeline Co. and its subsidiaries
Court of Appeals..................  United States Court of Appeals for the District of Columbia Circuit
East Tennessee....................  East Tennessee Natural Gas Company, a wholly owned subsidiary of El
                                    Paso Tennessee Pipeline Co.
EBIT..............................  Earnings before interest expense and income taxes, excluding
                                    affiliated interest income
EPA...............................  United States Environmental Protection Agency
EPEC..............................  El Paso Energy Corporation, which, on August 1, 1998, became the
                                    successor company to El Paso Natural Gas Company and, as of
                                    December 31, 1998, the parent of El Paso Tennessee Pipeline Co.
EPEI..............................  El Paso Energy International Company, a wholly owned subsidiary of
                                    El Paso Tennessee Pipeline Co.
EPEM..............................  El Paso Energy Marketing Company, a wholly owned indirect
                                    subsidiary of El Paso Tennessee Pipeline Co.
EPFS..............................  El Paso Field Services Company, a wholly owned subsidiary of El
                                    Paso Tennessee Pipeline Co.
EPMC..............................  El Paso Management Company, a subsidiary of El Paso Natural Gas
                                    Company and parent of El Paso Tennessee Pipeline Co. which merged
                                    with and into El Paso Natural Gas Company in July 31, 1998.
EPNG..............................  El Paso Natural Gas Company, a wholly owned subsidiary of El Paso
                                    Energy Corporation subsequent to August 1, 1998 and the parent
                                    company of El Paso Tennessee Pipeline Co. prior to December 31,
                                    1998
EPTPC.............................  El Paso Tennessee Pipeline Co. (formerly Tenneco Inc.), a direct
                                    subsidiary of El Paso Energy Corporation
FERC..............................  Federal Energy Regulatory Commission
GSR...............................  Gas supply realignment
IRS...............................  Internal Revenue Service
MBbls.............................  Thousand barrels
Midwestern........................  Midwestern Gas Transmission Company, a wholly owned subsidiary of
                                    El Paso Tennessee Pipeline Co.
Mgal/d............................  Thousand gallons per day
MMcf(/d)..........................  Million cubic feet (per day)
MMdth(/d).........................  Million decatherms (per day)
MW(s).............................  Megawatt(s)
New Tenneco.......................  Tenneco Inc., subsequent to the acquisition by El Paso Energy
                                    Corporation of Old Tenneco, consisting of the automotive parts,
                                    packaging and administrative services businesses
Old Tenneco.......................  Tenneco Inc. (renamed El Paso Tennessee Pipeline Co.), prior to the
                                    acquisition by El Paso Energy Corporation
PCB(s)............................  Polychlorinated biphenyl(s)
PLN...............................  Perusahaan Listrik Negara, the Indonesian government owned electric
                                    utility
PRP(s)............................  Potentially Responsible Party(ies)
</TABLE>
 
                                       ii
<PAGE>   4
 
<TABLE>
<CAPTION>
                                                                DEFINITION
                                                                ----------
<S>                                 <C>
Series A Preferred Stock..........  8 1/4% Cumulative Preferred Stock, Series A of El Paso Tennessee
                                    Pipeline Co.
Series B Preferred Stock..........  8 1/2% Cumulative Junior Preferred Stock, Series B of El Paso
                                    Tennessee Pipeline Co.
Series C Preferred Stock..........  6 1/4% Cumulative Junior Preferred Stock, Series C of El Paso
                                    Tennessee Pipeline Co.
SFAS..............................  Statement of Financial Accounting Standards
Tenneco Ventures..................  Tenneco Ventures Corporation and Tenneco Gas Production
                                    Corporation, collectively
TGP...............................  Tennessee Gas Pipeline Company, a wholly owned subsidiary of El
                                    Paso Tennessee Pipeline Co.
</TABLE>
 
                                       iii
<PAGE>   5
 
                                     PART I
 
ITEM 1. BUSINESS
 
                                    GENERAL
 
     In December 1996, EPNG acquired EPTPC. In March 1998, the energy marketing
operations of El Paso Marketing Services Company were transferred to EPTPC. On
December 31, 1998, EPTPC became a direct subsidiary of EPEC after a tax-free
internal reorganization. As a result of the March 1998 transfer and the December
1998 reorganization, the merchant services operations of EPEM, the international
operations of EPEI, and the field services operations of EPFS became
subsidiaries of EPTPC. Also, as part of the reorganization, EPTPC transferred
certain assets and liabilities of corporate and discontinued operations to EPEC.
EPTPC continues to own the interstate systems known as the TGP system, the East
Tennessee system, and the Midwestern system, as well as certain discontinued
operations not included in the transfer to EPEC. At December 31, 1998, EPEC owns
100 percent of the common equity and greater than 80 percent of the combined
equity value of EPTPC. The remaining combined equity value of EPTPC consists of
$300 million of outstanding preferred stock that is traded on the New York Stock
Exchange.
 
     The Company's principal operations include the interstate and intrastate
transportation, gathering and processing of natural gas; the marketing of
natural gas, power, and other commodities; and the development and operation of
energy infrastructure facilities worldwide. The Company owns or has interests in
over 17,800 miles of interstate and intrastate pipeline connecting the nation's
principal natural gas supply regions to three of the largest consuming regions
in the United States, namely the Gulf Coast, the Northeast and the Midwest. The
Company's natural gas transmission operations are comprised of three interstate
pipeline systems: the Tennessee Gas pipeline, the Midwestern Gas Transmission
pipeline, and the East Tennessee Natural Gas pipeline.
 
     In addition to its interstate transmission services, the Company provides
related services, including natural gas gathering, products extraction,
dehydration, purification, compression, and intrastate transmission. These
services include gathering of natural gas from more than 10,000 natural gas
wells with approximately 11,000 miles of gathering lines, and 23 natural gas
processing and treating facilities located in some of the most prolific and
active production areas of the United States, including the San Juan and Permian
Basins and in east Texas, south Texas, Louisiana, and the Gulf of Mexico. The
Company conducts intrastate transmission operations through its interests in
four Texas intrastate systems, which include the Oasis Pipeline running from
west Texas to Katy, Texas, the Channel Pipeline extending from south Texas to
the Houston Ship Channel, and the Shoreline and Tomcat gathering systems which
gather gas from offshore Texas. The Company also provides intrastate
transportation in north Louisiana through its Gulf States Pipeline that runs
from the Texas border to Ruston, Louisiana. The Company's marketing activities
include the marketing and trading of natural gas, power, and petroleum products,
as well as providing integrated price risk management services associated with
these commodities. The Company also participates in the development and
ownership of domestic power generation facilities, and other power-related
assets and joint ventures.
 
     The Company's international activities focus on the development and
operation of international energy infrastructure projects and include ownership
interests in three major operating natural gas transmission systems in
Australia, and natural gas transmission systems and power generation facilities
currently in operation or under construction in Argentina, Bolivia, Brazil,
Chile, the Czech Republic, Hungary, Indonesia, Mexico, Pakistan, Peru, the
United Kingdom, Bangladesh, the Philippines and China. The Company also has an
interest in three operating domestic power generation plants.
 
                                    SEGMENTS
 
     Beginning in 1998, the Company segregated its business activities into four
segments: Tennessee Gas Pipeline segment, El Paso Field Services segment, El
Paso Energy Marketing segment, and El Paso Energy International segment. These
segments are strategic business units that offer a variety of different energy
products and services. They are managed separately, as each business unit
requires different technology and
 
                                        1
<PAGE>   6
 
marketing strategies. For information relating to operating revenues, operating
income, EBIT, and identifiable assets attributable to each segment, see Item 8,
Financial Statements and Supplementary Data, Note 9.
 
     Set forth below is a description of the principal business activities
conducted by each of the Company's segments:
 
<TABLE>
<CAPTION>
<S>                                      <C>
Tennessee Gas Pipeline                   Provides interstate natural gas pipeline
                                         transportation to the northeast, midwest and
                                         mid-Atlantic sections of the U.S., including the
                                         states of Tennessee and Virginia as well as the New
                                         York City, Chicago and Boston metropolitan areas.
                                         Such transportation is conducted through the
                                         interstate pipeline systems of TGP, Midwestern and
                                         East Tennessee.
El Paso Field Services                   Provides natural gas gathering, products
                                         extraction, dehydration, purification, compression
                                         and intrastate natural gas transmission services.
El Paso Energy Marketing                 Markets and trades natural gas, power and petroleum
                                         products and provides integrated risk management
                                         services.
El Paso Energy International             Develops and operates energy infrastructure
                                         facilities worldwide.
</TABLE>
 
     In addition, the Company participates in the development and ownership of
domestic power generation projects.
 
TENNESSEE GAS PIPELINE
 
     The TGP system. The TGP system consists of approximately 14,700 miles of
pipeline with a design capacity of 5,512 MMcf/d. During 1998, TGP transported
natural gas volumes averaging approximately 80 percent of its capacity. The TGP
system serves the northeast section of the U.S., including the New York City and
Boston metropolitan areas. The multiple-line system begins in the gas-producing
regions of south Texas and Louisiana, including the Gulf of Mexico.
 
     The Midwestern system. The Midwestern system consists of approximately 400
miles of pipeline with a design capacity of 785 MMcf/d. During 1998, Midwestern
transported natural gas volumes averaging approximately 35 percent of its
capacity. The Midwestern system extends from a connection with the TGP system at
Portland, Tennessee, to Chicago and principally serves the Chicago metropolitan
area.
 
     The East Tennessee system. The East Tennessee system consists of
approximately 1,100 miles of pipeline with a design capacity of 675 MMcf/d.
During 1998, East Tennessee transported natural gas volumes averaging
approximately 45 percent of its capacity. The East Tennessee system serves the
states of Tennessee, Virginia and Georgia and connects with the TGP system in
Springfield and Lobelville, Tennessee.
 
     Other. The Company increased its ownership interest in the Portland Natural
Gas Transmission ("Portland") system from 17.8 percent to approximately 19
percent in April 1998. Portland is a 292-mile interstate natural gas pipeline
with initial capacity of 178 MMcf/d extending from the Canadian border near
Pittsburg, New Hampshire to Dracut, Massachusetts. In April 1998, Portland
secured $256 million in non-recourse project financing. Construction started in
June 1998, with an estimated total cost of $423 million. Portland commenced
commercial operations in March of 1999.
 
     From time to time, the Company holds open seasons in an effort to
capitalize on pipeline expansion opportunities. Currently, TGP has completed an
open season for the Eastern Express Project 2000 to provide gas transportation
for the growing markets in the Northeast. As a result, TGP filed an application
before FERC for the expansion in the first quarter of 1999 to begin service in
2000. TGP has received approval from FERC to construct an international border
crossing at Reynosa, Tamaulipas, Mexico, and interconnect with Pemex Gas y
Petroquimica Basica, a Mexican state-owned company ("Pemex") to provide the
import of gas from Mexico. The border crossing service is expected to begin in
1999.
 
                                        2
<PAGE>   7
 
  REGULATORY ENVIRONMENT
 
     The interstate systems are subject to the jurisdiction of FERC in
accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of
1978.
 
     In the mid-1980s, FERC initiated a series of actions which ultimately had
the effect of substantially removing interstate pipelines from the gas purchase
and resale business and confining their role to transportation of gas owned by
others. In Order No. 436, issued in 1985, FERC began this transition by
requiring interstate pipelines to provide non-discriminatory access to their
facilities for all transporters of natural gas. This requirement enabled
consumers to purchase their own gas and have it transported on the interstate
pipeline system, rather than purchase gas from the pipelines. The transition was
completed with Order No. 636, issued in 1992, in which FERC required all
interstate pipelines to "unbundle" their sales and transportation services so
that the transportation services they provided to third parties would be
"comparable" to the transportation services provided to gas owned by the
pipeline. FERC's stated purpose was to ensure that the pipelines' monopoly over
the transportation of natural gas did not distort the competition in the gas
producer sales market, which had, by then, been essentially deregulated.
 
     One of the obstacles to this transition was the existence of long-term gas
purchase contracts between pipelines and producers which required the pipelines
to take or pay for a significant percentage of the gas the producer was capable
of delivering. While FERC did not deal with this issue initially, it eventually
adopted rate recovery procedures which facilitated negotiations between
pipelines and producers to address take-or-pay issues. Such procedures were
established in Order Nos. 500, 528 and 636, in the last of which FERC provided
that pipelines could recover 100 percent of the costs prudently incurred to
terminate their gas purchase obligations. In July 1996, the Court of Appeals
issued its decision upholding, in large part, Order No. 636.
 
     In December 1994, TGP filed for a general rate increase with FERC and in
October 1996, FERC approved the settlement resolving that proceeding. The
settlement included a structural rate design change that resulted in a larger
portion of TGP's transportation revenues being dependent upon throughput. One
party, a competitor of TGP, filed a petition for review of the FERC orders with
the Court of Appeals. The Court of Appeals remanded the case to FERC to respond
to the competitor's argument that TGP's cost allocation methodology deterred the
development of market centers (centralized locations where buyers and sellers
can physically exchange gas) and, at FERC's request, comments were filed in
January 1999.
 
     For a further discussion of regulatory matters, see Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations.
 
  MARKETS AND COMPETITION
 
     The interstate systems face varying degrees of competition from alternative
energy sources, such as electricity, hydroelectric power, coal, and fuel oil.
The potential consequences of proposed and ongoing restructuring and
deregulation of the electric power industry are currently unclear. It may
benefit the natural gas industry by creating more demand for natural gas turbine
generated electric power, or it may hamper demand by allowing more effective use
of surplus electric capacity through increased wheeling as a result of open
access. At this time, the Company is not projecting a significant change in
natural gas demand as a result of such restructuring.
 
     Customers of TGP include natural gas producers, marketers and end-users, as
well as other gas transmission and distribution companies, none of which
individually represents more than 10 percent of the revenues on TGP's system.
Substantially all of the revenues of TGP are generated under long-term natural
gas transmission contracts. Contracts representing approximately 70 percent of
TGP's firm transportation capacity will be expiring over the next two years,
principally in November 2000. Although TGP cannot predict how much capacity will
be resubscribed, a majority of the expiring contracts cover service to
northeastern markets, where there is currently little excess capacity. Several
projects, however, have been proposed to deliver incremental volumes to these
markets. Although TGP is actively pursuing the renegotiation, extension and/or
replacement of these contracts, TGP cannot give any assurance that it will be
able to extend or replace these
 
                                        3
<PAGE>   8
 
contracts (or a substantial portion thereof) or that the terms of any
renegotiated contracts will be as favorable to TGP as the existing contracts.
 
     In a number of key markets, TGP faces competitive pressure from other major
pipeline systems, enabling local distribution companies and end-users to choose
a supplier or switch suppliers based on the short-term price of natural gas and
the cost of transportation. Competition among pipelines is particularly intense
in TGP's supply areas, Louisiana and Texas. In some instances, TGP has had to
discount its transportation rates in order to maintain market share. The
renegotiation of TGP's expiring contracts may be adversely affected by the
foregoing competitive factors.
 
EL PASO FIELD SERVICES
 
     EPFS was formed for the purpose of owning, operating, acquiring and
constructing natural gas gathering, processing and other related facilities.
Effective January 1, 1996, EPNG transferred its non-regulated assets to EPFS.
These assets included major natural gas gathering systems in the San Juan and
Permian Basins. From this initial asset base, EPFS began to implement plans to
increase natural gas gathering and processing volumes through a strategy of
project development, acquisitions, and joint ventures.
 
     EPFS provides its customers with wellhead-to-mainline field services,
including natural gas gathering and transportation, products extraction,
dehydration, purification and compression. EPFS also provides intrastate natural
gas transmission services. EPFS, together with EPEM, provides fully bundled
natural gas services with a broad range of pricing options as well as financial
risk management products. EPFS also provides well-ties and offers real-time
information services, including electronic wellhead gas flow measurement. EPFS
services are provided under a variety of fee structures including fixed fee per
decatherm, floating fee per decatherm indexed to the applicable local area price
of gas, or percentage of products sold.
 
     In August 1998, the Company completed the expansion of the Coyote Gulch
Treating Plant which increased capacity from 120 MMcf/d to 240 MMcf/d, providing
an additional outlet for coal seam gas production in southwestern Colorado.
 
     In September 1998, the Company completed the Global Compression project, a
$45 million capital investment that consists of 40,000 horsepower of
compression, gas dehydration facilities, and 54 miles of pipeline looping. The
project lowered wellhead pressures and increased production rates for 70 percent
of the wells from which EPFS gathers in the San Juan Basin.
 
     In September 1998, EPFS sold its natural gas gathering, treating, and
processing assets in the Anadarko Basin to Midcoast Energy Resources, Inc. for
$35 million.
 
     The following table provides information as of December 31, 1998,
concerning the natural gas gathering and transportation facilities, as well as
natural gas gathered/transported for the three years ended December 31:
 
<TABLE>
<CAPTION>
                                                                     AVERAGE THROUGHPUT
                                           MILES      THROUGHPUT          (BBTU/D)
                                            OF         CAPACITY     ---------------------
         GATHERING & TREATING           PIPELINE(1)   (MMCF/D)(2)   1998    1997    1996
         --------------------           -----------   -----------   -----   -----   -----
<S>                                     <C>           <C>           <C>     <C>     <C>
Western Division......................     5,555         1,200      1,191   1,167   1,139
Eastern Division......................       955           910        282     252     149
Central Division......................     1,266           933        427     408     373
Offshore Division.....................       410         2,040        780     314     227
Joint Owned Division..................       750           900        564       6       7
</TABLE>
 
                                        4
<PAGE>   9
 
     The following table provides information concerning the processing
facilities for the three years ended December 31:
 
<TABLE>
<CAPTION>
                                                                           AVERAGE NATURAL GAS
                                                      AVG INLET VOLUME        LIQUIDS SALES
                                                          (BBTU/D)              (MGAL/D)
                                          INLET      ------------------   ---------------------
          PROCESSING PLANTS            CAPACITY(2)   1998   1997   1996   1998    1997    1996
          -----------------            -----------   ----   ----   ----   -----   -----   -----
<S>                                    <C>           <C>    <C>    <C>    <C>     <C>     <C>
Western Division.....................      600       586    551    557     370     505     352
Eastern Division.....................      207       109    126     75     275     229     115
Central Division.....................      278       269     58     19     208      94      39
Joint Owned Division.................      199        51    102      6      74     167      --
</TABLE>
 
     The following table provides information concerning natural gas gathering
and transportation facilities in which EPFS owns a minority interest and
accounts for under the equity method:
 
<TABLE>
<CAPTION>
                                                                               AVERAGE THROUGHPUT
                                      PERCENT OF      MILES      THROUGHPUT         (BBTU/D)
                                      OWNERSHIP        OF         CAPACITY     -------------------
                                       INTEREST    PIPELINE(1)   (MMCF/D)(2)     1998     1997(3)
                                      ----------   -----------   -----------   --------   --------
<S>                                   <C>          <C>           <C>           <C>        <C>
Oasis Pipeline......................     35.0           608           350        289        338
Coyote Gulch........................     50.0            --           120         69         42
Viosca Knoll........................     50.0           125           500        287        205
</TABLE>
 
------------
 
(1) Mileage amounts are approximate for the total systems and have not been
    reduced to reflect EPFS's net ownership.
 
(2) All capacity information reflects EPFS's net interest and is subject to
    increases or decreases depending on operating pressures and point of
    delivery into or out of the system.
 
(3) Throughput for Oasis Pipeline was in El Paso Energy Marketing segment in
    1997.
 
     In January 1999, the Company and Leviathan Gas Pipeline Partners, L.P.
("Leviathan") entered into an agreement where the Company will sell, for
approximately $85 million, all of its interest in Viosca Knoll Gathering Company
to Leviathan except for a 1 percent interest in profits and capital. The
transaction was approved by Leviathan's board of directors in January 1999, and
at a special meeting held March 5, 1999, the Leviathan unitholders approved an
increase in the authorized number of common units required to complete the
acquisition. The transaction is expected to close in the second quarter of 1999.
 
  Competition
 
     EPFS operates in a highly competitive environment that includes independent
natural gas gathering and processing companies, intrastate pipeline companies,
natural gas marketers, and oil and gas producers. EPFS competes for throughput
primarily based on price, efficiency of facilities, gathering system line
pressures, availability of facilities near drilling activity, service, and
access to favorable downstream markets.
 
EL PASO ENERGY MARKETING
 
     EPEM, the Company's merchant services and trading business, utilizes its
extensive knowledge of the marketplace, natural gas pipeline and power
transmission infrastructure, supply aggregation, transportation management and
valuation, storage and integrated price risk management to provide customers
with flexible solutions to meet their energy supply and financial risk
management requirements. EPEM markets and trades natural gas, power, and
petroleum products in the United States, Canada and Mexico. EPEM has emerged as
one of North America's largest energy marketing and trading companies.
 
     EPEM contracts to purchase specific natural gas volumes from suppliers at
various times and points of receipt, arranges for the aggregation and
transportation of such natural gas, and negotiates the sale of these volumes to
utilities (including local distribution companies and power plants),
municipalities, and a variety of industrial and commercial end users. EPEM seeks
to maintain a balanced portfolio of supply and demand
 
                                        5
<PAGE>   10
 
contracts and a diverse natural gas supplier and customer base. During 1998, it
served over 400
producers/suppliers and approximately 2,000 sales customers in 26 states and
shipped natural gas supplies on 65 pipelines.
 
     EPEM utilizes a broad range of risk management instruments to manage its
fixed-price purchase and sales commitments and reduce its exposure to market
price volatility. EPEM trades futures contracts and options on the New York
Mercantile Exchange and trades swaps and options in over-the-counter financial
markets with other major energy merchants. Market risks are managed on a
portfolio basis, subject to parameters established by a risk control committee
that operates independently from commercial operations. Market risk in EPEM's
commodity derivative portfolio is measured on a daily basis utilizing a
Value-at-Risk (VAR) model to determine the maximum potential one-day unfavorable
impact on its earnings. For additional information regarding the use of
financial instruments, see Item 7A, Quantitative and Qualitative Disclosures
About Market Risk and Item 8, Financial Statements and Supplementary Data, Note
4.
 
     Set forth below are the marketed gas, power and petroleum volumes for the
years ended December 31:
 
<TABLE>
<CAPTION>
                                                             1998     1997     1996
                                                            ------   ------   -------
<S>                                                         <C>      <C>      <C>
Natural gas volumes marketed (BBtu/d)(1)..................  11,540    6,969     6,958
Power volumes marketed (Thousand MW hours)................  44,677   12,969     3,884
Petroleum volumes marketed (MBbls per year)(1)............  21,717   80,641    54,913
</TABLE>
 
---------------
 
(1) Includes financial trades.
 
  Competition
 
     EPEM operates in a highly competitive environment. Its primary competitors
include: (i) marketing affiliates of major oil and gas producers; (ii) marketing
affiliates of large local distribution companies; (iii) marketing affiliates of
other interstate and intrastate pipelines; and (iv) independent energy marketers
with varying scopes of operations and financial resources. EPEM competes on the
basis of price, access to production, understanding of pipeline and transmission
networks, imbalance management, and experience in the marketplace.
 
EL PASO ENERGY INTERNATIONAL
 
     EPEI was formed for the purpose of investing in integrated energy projects
with an emphasis on developing infrastructure to gather, transport and use
natural gas in northern Mexico and certain Latin American countries. The focus
of international project pursuit has expanded to include power generation and to
include investments located in Australia, Asia, Europe and other Latin American
countries. Set forth below are brief descriptions, by region, of the projects
that are either operational or in various stages of development.
 
     Acquisitions and greenfield development projects are subject to a higher
level of commercial and financial risk in foreign countries. Accordingly, EPEI
has adopted a risk mitigation strategy to reduce risks to more acceptable and
manageable levels. EPEI's practice is to select experienced partners with a
history of success in commercial operations. Individual partners are generally
chosen based on the complementary competencies which they offer to the various
joint ventures formed or to be formed. EPEI designs and implements a formal due
diligence plan on every project it pursues, and contracts are negotiated to
secure fuel supply, manage operating and maintenance costs and, when possible,
index revenues and denominate transactions in U.S. dollars. EPEI also obtains
political risk insurance when deemed appropriate, through the Overseas Private
Investment Corporation, the Multilateral Investment Guarantee Agency, or a
private insurer.
 
Latin America and Mexico
 
     Samalayuca Power Project -- The Company owns a 30 percent interest in a 700
MW combined cycle gas fired power plant in Samalayuca, Mexico. The first,
second, and third units commenced commercial operations in May, September, and
December 1998, respectively. Comision Federal de Electricidad, the
 
                                        6
<PAGE>   11
 
Mexican government-owned electric utility ("CFE") operates the plant under a
20-year lease. Upon expiration of the lease term, ownership of the plant will be
transferred to CFE.
 
     Samalayuca Pipeline -- This 45-mile 212 MMcf/d pipeline system commenced
gas deliveries in December 1997. The pipeline delivers natural gas to the
Samalayuca Power Project from EPNG's existing pipeline system in west Texas and
Pemex's pipeline system in northern Mexico. This system consists of 22 miles of
pipeline in the U.S. (currently owned by EPNG) and 23 miles of pipeline in
Mexico
(currently 40 percent owned by the Company and 10 percent owned by EPNG).
 
     Aguaytia Project -- The Company owns a 24 percent interest in an integrated
natural gas and power generation project near Pucallpa, located in central Peru.
The project consists of a 302 Bcf natural gas field, a natural gas processing
facility, a 71-mile natural gas liquids pipeline to a fractionation facility, a
126-mile natural gas pipeline to a 155 MW simple cycle power plant, and a
250-mile 220 KV power transmission line interconnecting with the Peruvian grid
at Paramonga. The project began operations in July 1998.
 
     CAPSA -- The Company has an effective 45 percent interest in CAPSA, a
privately held integrated energy company in Argentina. CAPSA was incorporated in
1977 for the purpose of producing, selling and exploring for liquid
hydrocarbons. CAPSA's assets include a 100 percent ownership interest in the
Diadema Oil Field and a 55 percent ownership interest in CAPEX, a publicly
traded company on the Argentine and Luxembourg stock exchanges that owns the 382
MW (currently being expanded to 650 MW) Agua del Cajon gas fired power plant in
western Argentina. This plant has been fully operational since 1995 and buys
natural gas from CAPEX's Agua del Cajon gas field. CAPEX also owns a 24 percent
interest in the 76 MW Energia del Sur gas fired power plant in southern
Argentina.
 
     Triunion Energy Company -- In January 1998, the Company, CAPEX and
InterEnergy formed a new development company named Triunion Energy Company
("Triunion Energy") to identify and develop new energy related projects in Latin
America. Triunion Energy currently owns a 20 percent interest in an exploration
and production project in Charagua, Bolivia, as well as a 22 percent interest in
an approved project to build a $380 million, 325 mile, natural gas pipeline that
will cross the Andes Mountains connecting natural gas production in Argentina's
Neuquen Basin to customers in Concepcion, Chile. Construction of the pipeline
commenced in early 1998 and is expected to be completed in late 1999.
 
     Manaus Power Project -- The Company owns 100 percent of a 250 MW power
plant in Manaus, the capital city of the state of Amazonas in northern Brazil.
Power from the plant is currently sold under a four-year contract to
Electronorte, the local electric company. The first phase of the project
commenced operations in February 1998. The second phase commenced operations in
March 1998 and the third phase commenced operations in June 1998. See Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations for additional discussion of the Manaus power project.
 
     Bolivia to Brazil Pipeline -- The Company is part of a consortium that is
constructing a 2,000 mile pipeline from Santa Cruz, Bolivia to Sao Paulo,
Brazil, with a southern lateral to Porto Alegre, Brazil. The pipeline will
transport natural gas to the largest unserved market in the western hemisphere
(approximately 100 million people). The pipeline is expected to be in service in
early 1999. The Company's interest in the project is approximately 8 percent.
 
     Parana Power Project -- The Company has an approximate 30 percent interest
in a consortium to build a 480 MW natural gas fired power plant in the state of
Parana, in southern Brazil. The power plant will be located in Araucaria,
Brazil. The electricity will be purchased by Companhia Paranaense de Energia, an
integrated electric utility providing generation, transmission, and distribution
of electricity to all regions of the state of Parana. The plant will be fueled
by natural gas provided from the Bolivia to Brazil pipeline. Final negotiation
and signing of a power purchase agreement will take place in early 1999 with
financial close expected in the fourth quarter of 1999. Commercial operations
are expected to commence in late 2000.
 
     Costanera -- In July 1998, the Company acquired 100 percent of KLT Power,
Inc. ("KLT Power"), the international business unit of Kansas City Power and
Light Company. KLT Power, was established in 1993, to develop, finance, own, and
operate independent power projects in selected markets worldwide. KLT Power owns
a 12 percent interest in Central Costanera, the largest thermal-power plant in
Argentina consisting of
                                        7
<PAGE>   12
 
2,167 MW of power generation and a 7.8 percent interest in Central
Termoelectrica Buenos Aires, S.A., a 328 MW combined cycle power plant in Buenos
Aires.
 
Europe
 
     EMA Power -- The Company owns a 50 percent controlling interest in a 70 MW
power plant located in Dunaujvaros, Hungary. The electricity generated at the
plant is consumed by Dunaferr Kft., the largest steel mill in Hungary. Approval
has been given to expand the capacity of the electric generating plant to 140 MW
and construction is scheduled to commence in late 1999.
 
     Kladno Power -- In May 1997, the Company acquired a 31 percent interest in
a 338 MW natural gas and coal fired expansion and upgrade of an existing 25 MW
cogeneration facility located approximately 19 miles northwest of Prague, in the
Czech Republic. The Company sold a 13 percent interest in the project to one of
the original partners under a buy back option granted by the Company in June
1997. The Company expects to purchase a similar amount in 1999 from another
partner under a similar option agreement. Non-recourse project financing was
finalized in June 1997, and commercial operations are expected to commence in
the fourth quarter of 1999.
 
     Fife Power -- In September 1998, the Company acquired a 50 percent interest
in the first Scottish independent power project located in Fife. The existing
plant consists of a simple cycle natural gas fired turbine generating 75 MW,
which commenced operations in the fourth quarter of 1998. Under Phase II, a
steam turbine will be added to produce a total combined-cycle generating
capacity of 115 MW. Financial close for Phase II is expected to occur in early
1999, and commercial operation is expected to commence in early 2001.
 
     Enfield -- In December 1998, the Company acquired a 25 percent interest in
Enfield Energy Center Limited. The 396 MW combined cycle natural gas turbine
power plant is under construction near London, England and is expected to be
operational by October 1999.
 
Asia Pacific
 
     Australian Pipelines -- The Company owns a 30 percent interest in the
Moomba to Adelaide pipeline system, a 488-mile natural gas pipeline in southern
Australia and the Ballera to Wallumbilla pipeline system, a 470-mile natural gas
pipeline in southwestern Queensland.
 
     In March 1998, the Company, through its 33.3 percent interest in Epic
Energy (WA) Pipeline Trust venture, purchased the 925-mile Dampier-to-Bunbury
natural gas pipeline in western Australia. This 550 MMcf/d pipeline system
serves a number of western Australian markets, including industrial end-users.
An expansion of the Dampier-to-Bunbury pipeline is currently underway to supply
additional natural gas to Alcoa, Worsley and Wesfarmers. The expansion,
scheduled for completion in fourth quarter of 1999, will expand the pipeline
capacity to 635 MMcf/d.
 
     Sengkang Project -- The Company has a 50 percent interest in a producing
natural gas field with proven reserves of 533 Bcf and a 47.5 percent interest in
a 135 MW power plant in Sengkang, South Sulawesi, Indonesia. The electricity
produced by the power plant is sold to PLN, the national electric utility, under
a long-term power purchase agreement. The power plant began simple cycle
commercial operation in September 1997, making it one of the first independent
power plants to operate in Indonesia. Combined cycle completion was in September
1998. For a discussion related to the effects on the project of the devaluation
of the Indonesian rupiah, see Item 7, Management's Discussion and Analysis of
Financial Condition and Results of Operations.
 
     Kabirwala Power -- The Company owns a 42 percent interest in a 151 MW
natural gas fired power plant currently under construction in Kabirwala,
Pakistan. Commercial operation is expected to commence in the second quarter of
1999. The power plant will sell electricity to the State Water and Power
Development Authority.
 
                                        8
<PAGE>   13
 
     Haripur -- The Company owns a 50 percent interest in a consortium formed to
construct a 115 MW oil and gas-fired power generation facility in Haripur,
Bangladesh. The plant will sell power to the Bangladesh Power Development Board
under a 15-year power purchase agreement. The plant is expected to be in service
by the end of May 1999.
 
     East Asia Power -- In 1998, the Company executed agreements to acquire a 46
percent interest in East Asia Power Resources Corporation ("EAPRC"), a publicly
traded company in the Philippines. EAPRC owns and operates three power
generation facilities in the Philippines and owns an interest in one power
generation facility in China, with a total generating capacity of 289 MW. EAPRC
also has options to acquire two additional power generation facilities in the
Philippines with an aggregate generating capacity of 123 MW. Electric power
generated by the facilities is supplied to a diversified base of customers
including National Power Corporation, the state-owned utility, private
distribution companies and industrial users. This acquisition was completed in
February 1999.
 
Other Projects
 
     The Company owns interests in three operating domestic power generation
plants consisting of a 17.5 percent interest in a 240 MW power plant in
Springfield, Massachusetts and a 50 percent interest in two additional
cogeneration projects in Florida with a combined generating capacity of 220 MW.
 
                         CORPORATE AND OTHER OPERATIONS
 
     Corporate and other operations include certain liabilities of EPTPC's
discontinued operations and businesses.
 
                                 ENVIRONMENTAL
 
     A description of the Company's environmental activities is included in Item
7, Management's Discussion and Analysis of Financial Condition and Results of
Operations, and is incorporated by reference herein.
 
                                   EMPLOYEES
 
     The Company had approximately 2,100 full-time employees on December 31,
1998. The Company has no collective bargaining arrangements, and no significant
changes in the workforce have occurred since December 31, 1998.
 
                      EXECUTIVE OFFICERS OF THE REGISTRANT
 
     The executive officers of EPTPC as of March 16, 1999, are set forth below.
For dates prior to August 1, 1998 (the effective date of the holding company
reorganization), references to positions held with EPEC refer instead to
positions held with EPNG.
 
<TABLE>
<CAPTION>
                 NAME                                            OFFICE                          AGE
                 ----                                            ------                          ---
<S>                                      <C>                                                     <C>
William A. Wise........................  Chairman of the Board, President and Chief Executive    53
                                         Officer
H. Brent Austin........................  Executive Vice President and Chief Financial Officer    44
Joel Richards III......................  Executive Vice President                                52
Britton White Jr.......................  Executive Vice President and General Counsel            55
</TABLE>
 
     Mr. Wise became the Chairman of the Board, President and Chief Executive
Officer of EPTPC in December 1996. Mr. Wise has been Chairman of the Board of
EPEC since January 1994 and Chief Executive Officer since January 1990. In July
1998, Mr. Wise also became the President of EPEC. He was President of EPEC from
April 1989 to April 1996. From March 1987 until April 1989, Mr. Wise was an
Executive Vice President of EPEC. From January 1984 to February 1987, he was a
Senior Vice President of EPEC. Mr. Wise is a member of the Board of Directors of
Battle Mountain Gold Company and is the chairman of the Board of EPNG and
Leviathan Gas Pipeline Company, the general partner of Leviathan Gas Pipeline
Partners, L.P.
 
                                        9
<PAGE>   14
 
     Mr. Austin has been Executive Vice President and Chief Financial Officer of
EPTPC since June 1997. From December 1996 until June 1997, he was Senior Vice
President and Chief Financial Officer. Mr. Austin has been Executive Vice
President of EPEC since May 1995. He has been Chief Financial Officer of EPEC
since April 1992. He was Senior Vice President of EPEC from April 1992 to April
1995. He was Vice President, Planning and Treasurer of Burlington Resources Inc.
("BR") from November 1990 to March 1992 and Assistant Vice President, Planning
of BR from January 1989 to October 1990.
 
     Mr. Richards has been Executive Vice President of EPTPC since June 1997.
From December 1996 until June 1997, he was Senior Vice President. Mr. Richards
has been Executive Vice President of EPEC since December 1996. From January 1991
until December 1996, he was Senior Vice President of EPEC. He was Vice President
from June 1990 to December 1990. He was Senior Vice President, Finance and Human
Resources of Meridian Minerals Company, a wholly owned subsidiary of BR, from
October 1988 to June 1990.
 
     Mr. White has been Executive Vice President and General Counsel of EPTPC
since June 1997. From December 1996 until June 1997, he was Senior Vice
President and General Counsel. Mr. White has been Executive Vice President of
EPEC since December 1996 and General Counsel of EPEC from March 1991. He was
Senior Vice President and General Counsel of EPEC from March 1991 until December
1996. From March 1991 to April 1992, he was also Corporate Secretary of EPEC.
For more than five years prior to that time, Mr. White was a partner in the law
firm of Holland & Hart.
 
     Executive officers hold offices until their successors are elected and
qualified, subject to their earlier removal.
 
ITEM 2. PROPERTIES
 
     A description of the Company's properties is included in Item 1, Business,
and is incorporated by reference herein.
 
     The Company is of the opinion that it has generally satisfactory title to
the properties owned and used in its businesses, subject to the 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 its businesses. The
Company believes that its physical properties are adequate and suitable for the
conduct of its business in the future.
 
ITEM 3. LEGAL PROCEEDINGS
 
     See Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations, Commitments and Contingencies, Legal Proceedings, which
is incorporated herein by reference.
 
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
 
     None
 
                                       10
<PAGE>   15
 
                                    PART II
 
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
        STOCKHOLDER MATTERS
 
     Following the acquisition by EPEC, a subsidiary of EPEC became the sole
holder of EPTPC's common stock, par value $.01 per share (the "Common Stock").
The Common Stock was delisted from the New York Stock Exchange, and there is no
longer a trading market for such securities. The Series A Preferred Stock is
listed for trading on the New York Stock Exchange under the trading symbol
"EPG_p".
 
     As part of the tax-free internal reorganization, EPEC became the sole
holder of EPTPC's 1,971 shares of common stock.
 
     The declaration of dividends on EPTPC capital stock is at the discretion of
its Board of Directors. The Board of Directors has not adopted a dividend policy
as such; subject to legal and contractual restrictions, its decisions regarding
dividends are based on all considerations that in its business judgment are
relevant at the time, including past and projected earnings, cash flows,
economic, business and securities market conditions and anticipated developments
concerning EPTPC's business and operations.
 
     Dividends on the Series A Preferred Stock are payable when, as, and if
declared by EPTPC's Board of Directors. Dividends on such Series A Preferred
Stock accrue, whether or not declared, on a daily basis. The dividend rate on
the Series A Preferred Stock is 8 1/4% of $50 per share per annum (2.0625% per
quarter). The dividend payment dates on such shares are March 31, June 30,
September 30, and December 31, in each year. All dividends payable on
outstanding shares of the Series A Preferred Stock of quarterly periods ending
on or prior to December 31, 1998, have been paid in full.
 
                                       11
<PAGE>   16
 
ITEM 6. SELECTED FINANCIAL DATA
 
     In March 1998, the energy marketing operations of El Paso Marketing
Services Company were transferred to EPTPC. On December 31, 1998, EPEC, the
Company's ultimate parent, completed a tax-free internal reorganization of its
assets and operations and those of its subsidiaries in accordance with a private
letter ruling from the IRS. As a result of the March 1998 transfer and the
December 1998 reorganization, the merchant services operations of EPEM, the
international operations of EPEI, and the field services operations of EPFS
became subsidiaries of EPTPC. Also, as part of the reorganization, EPTPC
transferred certain assets and liabilities of corporate and discontinued
operations to EPEC. These transactions were treated as a transfer of ownership
between entities under common control and accounted for in a manner similar to a
pooling of interests. Accordingly, the Company's financial statements have been
restated to reflect these transactions for all periods presented. The
consolidated selected financial data as of December 31, 1998, and 1997 and for
the years ended December 31, 1998, 1997, and 1996 were derived from the audited
consolidated financial statements of the Company. The consolidated selected
financial data as of December 31, 1996, 1995, and 1994 and for the years ending
1995 and 1994 is unaudited and was derived from the accounting records of the
Company. The consolidated selected financial data as of December 31, 1998, 1997,
and 1996, reflect the acquisition of EPTPC by EPEC. In the opinion of EPTPC's
management, the combined selected financial data of the Company as of December
31, 1996, 1995, and 1994 and for the years ending 1995 and 1994 includes all
adjusting entries (consisting only of normal recurring adjustments) necessary to
present fairly the information set forth therein.
 
<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31,
                                                    -------------------------------------------
                                                     1998     1997    1996(A)    1995     1994
                                                    ------   ------   -------   ------   ------
                                                                   (IN MILLIONS)
<S>                                                 <C>      <C>      <C>       <C>      <C>
Operating Results Data:
  Operating revenues..............................  $5,308   $5,117   $5,008    $2,462   $2,701
  Extraordinary loss, net of income tax(b)........      --       --     (234)       --       --
  Net income (loss)...............................     225      130      (71)      155      159
</TABLE>
 
<TABLE>
<CAPTION>
                                                                   DECEMBER 31,
                                                    -------------------------------------------
                                                     1998     1997    1996(A)    1995     1994
                                                    ------   ------   -------   ------   ------
                                                                   (IN MILLIONS)
<S>                                                 <C>      <C>      <C>       <C>      <C>
Financial Position Data:
  Total assets....................................  $7,526   $7,563   $7,876    $6,383   $6,069
  Long-term debt..................................   1,467    1,082    1,152     1,811    2,242
  Stockholders' or combined equity................   2,153    1,913    1,776     1,195      558
</TABLE>
 
---------------
 
(a) Increases in operating revenues, total assets and combined equity between
    1995 and 1996 are primarily due to (i) the growth of the energy marketing
    businesses through the acquisitions of Eastex Energy, Inc. and Premier Gas
    Company in late 1995, (ii) the transfer on January 1, 1996, of EPNG's
    non-regulated gathering and processing operations and (iii) the acquisition
    of EPTPC by EPEC.
 
(b) Reflects extraordinary losses as a result of the retirement of long-term
    debt in the debt realignment immediately prior to the acquisition by EPEC.
 
                                       12
<PAGE>   17
 
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS
 
                                    GENERAL
 
     In December 1996, EPNG acquired EPTPC. In March 1998, the energy marketing
operations of El Paso Marketing Services Company were transferred to EPTPC. On
December 31, 1998, EPTPC became a direct subsidiary of EPEC after a tax-free
internal reorganization. As a result of the March 1998 transfer and the December
1998 reorganization, the merchant services operations of EPEM, the international
operations of EPEI, and the field services operations of EPFS became
subsidiaries of EPTPC. The value of the transfers associated with the tax-free
reorganization was $667 million, which represented the book value of those items
exchanged at the date of transfer. Also, as part of the reorganization, EPTPC
transferred certain assets and liabilities of corporate and discontinued
operations to EPEC. EPTPC continues to own the interstate systems known as the
TGP system, the East Tennessee system, and the Midwestern system, as well as
certain discontinued operations not included in the transfer to EPEC. At
December 31, 1998, EPEC owns 100 percent of the common equity and greater than
80 percent of the combined equity value of EPTPC. The remaining combined equity
value of EPTPC consists of $300 million of outstanding preferred stock that is
traded on the New York Stock Exchange. The tax-free reorganization has been
treated as a transfer of ownership between entities under common control and
accounted for in a manner similar to a pooling of interests. Accordingly, all
information included herein has been restated as though the transactions
occurred at the beginning of the earliest period presented.
 
                             RESULTS OF OPERATIONS
 
     The Company adopted the provisions of SFAS No. 131, Disclosures about
Segments of an Enterprise and Related Information, effective December 31, 1998.
Accordingly, the Company has segregated its business activities into four
segments: Tennessee Gas Pipeline segment, El Paso Field Services segment, El
Paso Energy Marketing segment, and El Paso Energy International segment. These
segments are strategic business units that offer a variety of different energy
products and services. They are managed separately as each business segment
requires different technology and marketing strategies. Certain business
segments' earnings are largely derived from the earnings of equity investments.
Accordingly, the Company evaluates segment performance based on EBIT. The
results of operations have been restated to reflect for all periods presented
the tax-free internal reorganization discussed above.
 
     Consolidated EBIT for the year ended December 31, 1998, increased 37
percent to $471 million compared to $344 million in the year ago period.
Consolidated EBIT for the year ended December 31, 1997, was $13 million lower
than for the same period of 1996. Variances are discussed in the segment results
below.
 
SEGMENT RESULTS
 
     To the extent practicable, results of operations for 1997 and 1996 have
been reclassified to conform to the current business segment presentation and
the effect of the tax-free internal reorganization, although such results are
not necessarily indicative of the results which would have been achieved had the
revised business segment structure or the tax-free internal reorganization been
in effect during those periods. Operating revenues and expenses by segment
include intersegment sales and expenses which are eliminated in consolidation.
Because of energy commodity price volatility, the Company believes that gross
margin (revenue less cost of sales), rather than operating revenue, provides a
more accurate indicator for the El Paso Field
 
                                       13
<PAGE>   18
 
Services and the El Paso Energy Marketing segments. For a further discussion of
the individual segments, see Item 8, Financial Statements and Supplementary
Data, Note 9.
 
<TABLE>
<CAPTION>
                                                                YEAR ENDED DECEMBER 31,
                                                              ---------------------------
                                                              1998       1997       1996
                                                              -----      -----      -----
                                                                     (IN MILLIONS)
<S>                                                           <C>        <C>        <C>
EARNINGS BEFORE INTEREST EXPENSE AND INCOME TAXES
Tennessee Gas Pipeline......................................  $ 358      $ 318      $ 311
El Paso Field Services......................................     78         74         52
El Paso Energy Marketing....................................      9        (28)        (1)
El Paso Energy International................................     25          2          6
Corporate expenses, net.....................................      1        (22)       (11)
                                                              -----      -----      -----
  Consolidated EBIT.........................................  $ 471      $ 344      $ 357
                                                              =====      =====      =====
</TABLE>
 
TENNESSEE GAS PIPELINE
 
<TABLE>
<CAPTION>
                                                                YEAR ENDED DECEMBER 31,
                                                              ---------------------------
                                                              1998       1997       1996
                                                              -----      -----      -----
                                                                     (IN MILLIONS)
<S>                                                           <C>        <C>        <C>
Operating revenues..........................................  $ 766      $ 798      $ 797
Operating expenses..........................................   (434)      (494)      (544)
Other -- net................................................     26         14         58
                                                              -----      -----      -----
  EBIT......................................................  $ 358      $ 318      $ 311
                                                              =====      =====      =====
</TABLE>
 
     YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
 
     Operating revenues for the year ended December 31, 1998, were $32 million
lower than for the same period of 1997 primarily because of lower throughput
resulting from warmer average temperatures in the northeastern and midwestern
markets and a downward revision in the amount of recoverable interest on GSR
costs.
 
     Operating expenses for the year ended December 31, 1998, were $60 million
lower than for the same period of 1997 primarily due to lower system fuel usage
associated with operating efficiencies attained during the period of lower
throughput, reduced operation and maintenance expenses largely due to lower
payroll costs, and lower franchise taxes.
 
     Other -- net for the year ended December 31, 1998, was $12 million higher
than for the same period of 1997 due to interest income on a favorable sales and
use tax settlement and gains on the sale of assets.
 
     YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
 
     Operating revenues for the year ended December 31, 1997, were $1 million
higher than for the same period of 1996 primarily due to new system rates on TGP
which went into effect November 1, 1996. The increase was offset by reduced
revenues attributable to the sale of the Bastian Bay assets whose revenues are
included in the 1996 total.
 
     Operating expenses for the year ended December 31, 1997, were $50 million
lower than for the same period of 1996, primarily due to lower labor and benefit
costs attributable to a reduction in staffing levels which occurred throughout
the latter half of 1996 and the first quarter of 1997, as well as lower legal
costs and operating and maintenance costs. The decrease in operating expenses
was partially offset by an increase in depreciation expense as a result of the
amortization of additional acquisition cost assigned to utility plant, as well
as new lower fuel retention rates starting in the second quarter of 1997.
 
                                       14
<PAGE>   19
 
     Other -- net for the year ended December 31, 1997, was $44 million lower
than for the same period of 1996 due to the recognition in February 1996 of a
gain on the sale of the Company's 50 percent general partnership interest in
Tenneco Mobile Bay Gathering Co., a favorable legal settlement in the second
quarter of 1996, and lower equity income from unconsolidated subsidiaries in
1997.
 
EL PASO FIELD SERVICES
 
<TABLE>
<CAPTION>
                                                             YEAR ENDED DECEMBER 31,
                                                             -----------------------
                                                             1998     1997     1996
                                                             -----    -----    -----
                                                                  (IN MILLIONS)
<S>                                                          <C>      <C>      <C>
Gathering and treating margin..............................  $ 150    $ 119    $  96
Processing margin..........................................     48       55       50
Other margin...............................................      3        6        2
                                                             -----    -----    -----
          Total gross margin...............................    201      180      148
Operating expenses.........................................   (138)    (114)    (106)
Other -- net...............................................     15        8       10
                                                             -----    -----    -----
  EBIT.....................................................  $  78    $  74    $  52
                                                             =====    =====    =====
</TABLE>
 
     YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
 
     Total gross margin for the year ended December 31, 1998, was $21 million
higher than for the same period of 1997. The increase in the gathering and
treating margin primarily resulted from higher gathering rates compared to 1997,
an increase in gathering and treating volumes largely attributable to the
acquisition of PacifiCorp's Texas Gulf Coast ("TPC") gathering and processing
subsidiaries in December 1997, and the inclusion of the results of operations of
Channel Pipeline ("Channel"), in El Paso Field Services segment beginning
January 1998 versus the El Paso Energy Marketing segment. The decrease in the
processing margin was largely attributable to lower liquids prices during 1998
compared to the same period of 1997. Liquids prices directly impact EPFS's
processing revenues. During 1998, liquids prices were at their lowest level
since 1990, and the Company expects this trend to continue through 1999. The
Company attempts to mitigate the impact of lower liquids prices by utilizing
hedging strategies where possible.
 
     Operating expenses for the year ended December 31, 1998, were $24 million
higher than for the same period of 1997 primarily as a result of additional
expenses associated with the addition of TPC and Channel as well as higher
general and administrative expenses.
 
     Other -- net for the year ended December 31, 1998, was $7 million higher
than for the same period of 1997 reflecting higher earnings from equity
investments and higher capitalized interest.
 
     YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
 
     Total gross margin for the year ended December 31, 1997, was $32 million
higher than for the same period of 1996. The increase in the gathering and
treating margin and the processing margin was primarily the result of higher
natural gas prices in the San Juan Basin and an increase in gathering and
treating volumes due to the acquisition of Cornerstone Natural Gas, Inc. in June
1996.
 
     Operating expenses for the year ended December 31, 1997, were $8 million
higher than for the same period of 1996 primarily due to the acquisition of
Cornerstone Natural Gas, Inc. partially offset by lower benefit expenses.
 
                                       15
<PAGE>   20
 
EL PASO ENERGY MARKETING
 
<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31,
                                                              -----------------------
                                                              1998     1997     1996
                                                              -----    -----    -----
                                                                   (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
Natural gas margin..........................................  $ 26     $ 25     $ 59
Power margin................................................    16       --        1
Petroleum products margin...................................     1       (3)       3
                                                              ----     ----     ----
          Total gross margin................................    43       22       63
Operating expenses..........................................   (38)     (53)     (68)
Other -- net................................................     4        3        4
                                                              ----     ----     ----
  EBIT......................................................  $  9     $(28)    $ (1)
                                                              ====     ====     ====
</TABLE>
 
     YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
 
     Total gross margin for the year ended December 31, 1998, was $21 million
higher than for the same period of 1997. Increases in total gross margin in 1998
reflect a fundamental shift in focus initiated by the energy marketing business
segment from a short-term positional trading operation to a long-term,
asset-based origination, trading, and risk management operation. In 1998, such
energy activities emphasized long-term power and gas contract management and
related energy services for power and natural gas customers, including
independent power producers, utilities and end users. Trading activities, while
substantially increasing in volume in 1998, are primarily used to manage risk in
long-term contract positions. Partially offsetting the increase in gross margin
was the impact of reporting the operations of Channel in El Paso Field Services
segment versus El Paso Energy Marketing segment beginning in January 1998.
Effective December 31, 1998, the operations related to power trading were
transferred to El Paso Power Services, a subsidiary of EPEC.
 
     Operating expenses for the year ended December 31, 1998, were $15 million
lower than for the same period of 1997. The decrease was attributable to the
1997 restructuring of the marketing organization and the transfer of Channel
operations as mentioned above.
 
     YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
 
     Total gross margin for the year ended December 31, 1997, was $41 million
lower than for the same period of 1996. The decrease resulted from generally
lower industry-wide gas marketing margins in the second quarter of 1997, as well
as extreme market volatility which negatively impacted the Company's natural gas
marketing activities and trading positions during the first quarter of 1997.
Partially offsetting this decrease was generally higher volumes from the
assignment of contracts in the third quarter of 1997 and higher industry-wide
gas marketing margins in the third and fourth quarters of 1997.
 
     Operating expenses for the year ended December 31, 1997, were $15 million
lower than for the same period of 1996 primarily due to lower general and
administrative expenses and a decrease in depreciation expense.
 
EL PASO ENERGY INTERNATIONAL
 
<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31,
                                                              -----------------------
                                                              1998     1997     1996
                                                              -----    -----    -----
                                                                   (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
Operating revenues..........................................  $ 58     $ 13     $ 37
Operating expenses..........................................   (86)     (37)     (43)
Other -- net................................................    53       26       12
                                                              ----     ----     ----
  EBIT......................................................  $ 25     $  2     $  6
                                                              ====     ====     ====
</TABLE>
 
                                       16
<PAGE>   21
 
     YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
 
     Operating revenues for the year ended December 31, 1998, were $45 million
higher than for the same period of 1997 due to the consolidation for financial
reporting purposes of the Manaus Power project in May 1998 after acquiring an
additional ownership interest and an increase in revenue attributable to the EMA
Power project which the Company began reporting on a consolidated basis in July
1997.
 
     Operating expenses for the year ended December 31, 1998, were $49 million
higher than for the same period of 1997 primarily due to costs related to the
consolidation of the EMA Power and Manaus Power projects and increased general
and administrative expenses largely due to higher project development costs
reflecting an increase in project-related activities in 1998.
 
     Other -- net for the year ended December 31, 1998, was $27 million higher
than for the same period of 1997 primarily due to increased equity earnings, a
gain on the sale of surplus power equipment, and the recognition of certain net
gains from project-related activities.
 
     As EPEI's projects move from the development stage to the operational
stage, it is common to recognize one-time gains and fees, which may include
management fees, development fees, financing fees, and gains on the sell-down of
ownership interests. The Company anticipates additional one-time events may
result in the recognition of income or expense in the future.
 
     YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
 
     Operating revenues and operating expenses for the year ended December 31,
1997, were $24 million lower and $6 million lower, respectively, than for the
same period of 1996. The decreases were due to the sale of 70 percent of the
Company's interests in two natural gas pipeline systems in Australia in 1996.
Following the sale, the Company's retained interests in the Australian natural
gas pipelines operations were accounted for by the equity method. In addition,
partially offsetting the net decrease was the EMA Power project which the
Company began reporting on a consolidated basis in July 1997.
 
     Other -- net for the year ended December 31, 1997, was $14 million higher
than for the same period of 1996 primarily due to the recognition of
project-related activity income, higher interest income, and increased equity
earnings.
 
CORPORATE EXPENSES, NET
 
     YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
 
     Net corporate expenses for the year ended December 31, 1998, were $23
million lower than for the same period of 1997. The decrease results from lower
benefit costs, an increase in investment income, and nonrecurring gains.
 
     YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
 
     Net corporate expenses for the year ended December 31, 1997, were $11
million higher than for the same period of 1996 due primarily to the
discontinuance of El Paso Energy Credit Corporation's commercial activities, the
sale of Tenneco Ventures, and the recognition of a deferred gain on the sale of
certain investments which occurred in 1996. In addition, benefit costs were
higher in 1997.
 
INTEREST AND DEBT EXPENSE
 
     YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
 
     Interest and debt expense for the year ended December 31, 1998 was $11
million higher than for the same period in 1997 primarily due to an increase in
long-term borrowings. The increase was partially offset by a decrease in
short-term borrowings, and the 1997 interest on the rate refund to TGP's
customers.
 
                                       17
<PAGE>   22
 
     YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
 
     Interest and debt expense for the year ended December 31, 1997 was $10
million lower than for the same period in 1996 primarily due to the reduction of
EPTPC's revolving credit facility in 1997.
 
INCOME TAX EXPENSE
 
     YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
 
     Income tax expense for 1998 was $94 million compared to $73 million for
1997. The effective tax rate was 29 percent and 36 percent for 1998 and 1997,
respectively. The effective tax rate for 1998 was lower than 1997 primarily as a
result of increased consolidated foreign income subject to foreign tax rates
different than U.S. tax rates, increased equity income from unconsolidated
foreign affiliates recorded net of foreign income taxes for which no provision
for U.S. income tax is required, and lower state income taxes.
 
     YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
 
     Income tax expense for 1997 was $73 million compared to $43 million for
1996. The effective tax rate was 36 percent and 21 percent for 1997 and 1996,
respectively. The effective tax rate for 1997 was higher than 1996 primarily as
a result of the 1996 reversal of a $38 million valuation allowance for deferred
tax assets.
 
1996 EXTRAORDINARY LOSS
 
     In 1996, in preparation for the acquisition by EPEC, Old Tenneco initiated
a realignment of its indebtedness. Upon completion of the debt realignment
transactions, the Company is only responsible for its remaining debt which was
not tendered, exchanged, defeased or otherwise retired (approximately $265
million of such debt remained outstanding immediately after the acquisition by
EPEC). The Company recognized an after-tax extraordinary charge of $234 million
related to the debt realignment immediately prior to the acquisition by EPEC.
 
                        LIQUIDITY AND CAPITAL RESOURCES
 
CASH FROM OPERATING ACTIVITIES
 
     Net cash provided by operating activities was $804 million for the year
ended December 31, 1998, compared to $507 million for 1997. The increase was
primarily due to a rate refund made to TGP's customers in the first quarter of
1997, higher net tax refunds in 1998, and changes in working capital. The
increase was partially offset by lower GSR collections in 1998.
 
CASH FROM INVESTING ACTIVITIES
 
     Net cash used in investing activities was $814 million for the year ended
December 31, 1998. Investment activities included expenditures for joint
ventures, equity investments, and capital expenditures. Expenditures related to
joint ventures and equity investments were primarily attributable to the El Paso
Energy International segment. Internally generated funds, supplemented by other
financing activities, were used to fund these expenditures.
 
     The Company's planned capital and investment expenditures for 1999 of
approximately $850 million are primarily for expansion of international
operations and domestic unregulated operations, pipeline systems activities and
other facilities, and computer and communication system enhancements.
 
     Funding for capital expenditures, acquisitions, and other investing
expenditures is expected to be provided by internally generated funds,
commercial paper issuance, available capacity under existing credit facilities,
the issuance of other long-term debt or equity, and/or contributions from EPEC.
 
                                       18
<PAGE>   23
 
CASH FROM FINANCING ACTIVITIES
 
     Net cash provided by financing activities was $3 million for the year ended
December 31, 1998. In October 1998, TGP issued debentures due 2028 for net
proceeds of $391 million. These proceeds, supplemented by internally generated
funds, were used to retire long-term debt, pay dividends, fund capital and
equity investments, and for other corporate purposes.
 
     Future funding for long-term debt retirements, dividends, and other
financing expenditures is expected to be provided by internally generated funds,
available capacity under existing credit facilities, the issuance of long-term
debt or equity, and/or contributions from EPEC.
 
LIQUIDITY
 
     The Company relies on cash generated from internal operations as its
primary source of liquidity, supplemented by its available credit facilities and
commercial paper program. In October 1997, EPNG established a new $750 million
five-year revolving credit and competitive advance facility and a new $750
million 364-day renewable revolving credit and competitive advance facility
(collectively, the "Revolving Credit Facility"). EPTPC and TGP are also parties
to the Revolving Credit Facility. In connection with the establishment of the
Revolving Credit Facility, EPTPC's revolving credit facility was terminated, and
the outstanding balance of $417 million was financed under the five-year portion
of the new Revolving Credit Facility with TGP designated as the borrower. The
availability under the Revolving Credit Facility is expected to be used for
general corporate purposes including, but not limited to, backstopping EPNG's
and TGP's $1 billion commercial paper programs.
 
     In August 1998, EPEC became a guarantor of EPNG's Revolving Credit
Facility. In October 1998, the $750 million 364-day portion of the Revolving
Credit Facility was amended to extend the termination date to October 27, 1999.
In addition, in October 1998, the Revolving Credit Facility was amended to
permit TGP to issue commercial paper, provided that the total amount of
commercial paper outstanding at EPNG and TGP is equal to or less than the unused
capacity under the Revolving Credit Facility. The interest rate on the Revolving
Credit Facility is 40 basis points above LIBOR, with the spread varying based on
EPEC's long-term debt credit rating.
 
     The availability of borrowings under the Company's credit agreements is
subject to certain specified conditions, which management believes the Company
currently meets. 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 since the specified dates).
 
     In March 1997, TGP issued $300 million aggregate principal amount of 7 1/2%
debentures due 2017, $300 million aggregate principal amount of 7% debentures
due 2027, and $300 million aggregate principal amount of 7 5/8% debentures due
2037. Proceeds of approximately $883 million, net of issuance costs, were used
to repay a portion of EPTPC's credit facility and for general corporate
purposes.
 
     In September 1998, TGP filed a shelf registration permitting TGP to offer
up to $600 million (including $100 million carried forward from a prior shelf
registration) of debt securities. In October 1998, TGP issued $400 million
aggregate principal amount of 7% debentures due 2028. Proceeds to TGP were
approximately $391 million, net of issuance costs. Approximately $300 million of
the proceeds were used to repay TGP's short-term indebtedness under the
Revolving Credit Facility and the remainder were used by TGP for general
corporate purposes. After this issuance, TGP has $200 million of capacity
remaining under its existing shelf registration.
 
     In August 1998, EPTPC retired its outstanding 10% debentures in the amount
of $38 million.
 
                                       19
<PAGE>   24
 
COMMITMENTS AND CONTINGENCIES
 
     Indonesia
 
     The Company owns a 47.5 percent interest in a power generating plant in
Sengkang, South Sulawesi, Indonesia. Under the terms of the project's power
purchase agreement, PLN purchases power from the Company in Indonesian rupiah
indexed to the U.S. dollar at the date of payment. Due to the devaluation of the
rupiah, the cost of power to PLN has significantly increased. PLN is currently
unable to pass this increase in cost on to its customers without creating
further political instability. PLN has requested financial aid from the Minister
of Finance to help ease the effects of the devaluation. PLN has been paying the
Company in rupiah indexed to the U.S. dollar at the rate in effect prior to the
rupiah devaluation, with a commitment to pay the balance when financial aid is
received. The difference between the current and prior exchange rate has
resulted in an outstanding balance due from PLN of $9.4 million at December 31,
1998. The Company continues to meet with PLN on a regular basis to resolve the
payment in arrears issue but has been unsuccessful to date. Recently, the
Company has met and discussed its situation and concerns with the World Bank,
the International Monetary Fund, the Overseas Private Investment Corporation,
and the U.S. Treasury Department in an attempt to achieve a resolution through
the Indonesian Minister of Finance. The Company will meet with PLN in April 1999
to discuss payments in arrear and the terms of a contract rationalization
process proposed by PLN. The Company has informed PLN that all payments in
arrear must first be received as a prerequisite to any further discussions on
contract rationalization. The Company cannot predict with certainty the outcome
of such discussions. The Company's total investment in the Sengkang project was
approximately $25 million at December 31, 1998. Additionally, the Company has
provided specific recourse guarantees of up to $6 million for loans from the
project lenders. All other project debt is non-recourse. The Company has
political risk insurance on the Sengkang project. The Company believes the
current economic difficulties in Indonesia will not have a material adverse
effect on the Company's financial position, results of operations, or cash
flows.
 
     Brazil
 
     The Company owns 100 percent of a 250 MW power plant in Manaus, Brazil.
Power from the plant is currently sold under a four-year contract to
Electronorte, denominated in Brazilian real. Due to the devaluation of the real
in January 1999, Manaus suffered an $831,000 exchange loss on the December
invoice. There is no provision in the contract to recover the effects of the
devaluation on this invoice. However, future invoices are covered under a
provision in the contract entitling the Company to recover a substantial portion
of any future devaluation. The Company believes the current economic
difficulties in Brazil will not have a material adverse effect on the Company's
financial position, results of operations, or cash flows.
 
     The contract for the Manaus power project provides for delay damages to be
paid to Electronorte if the specified construction schedule was not met.
Completion of the project was delayed beyond the originally scheduled completion
dates provided in the contract and such delays have resulted in a claim by
Electronorte for delay damages. The Company is in discussions with Electronorte
regarding such claim. In any event, the Company has the right under its
construction contract to assert claims against the construction contractor for
such delay damages and believes that any such damages will not have a material
adverse effect on the Company's financial position, results of operations, or
cash flows.
 
  Capital Commitments
 
     At December 31, 1998, the Company had capital and investment commitments of
$245 million, which are expected to be funded through internally generated funds
and/or incremental borrowings. The Company's other planned capital and
investment projects are discretionary in nature, with no substantial capital
commitments made in advance of the actual expenditures.
 
                                       20
<PAGE>   25
 
  Purchase Obligations
 
     In connection with the financing commitments of certain joint ventures, TGP
has entered into unconditional purchase obligations for products and services
totaling $77 million at December 31, 1998. TGP's annual obligations under these
agreements are $21 million for the years 1999 and 2000, $11 million for the year
2001, $4 million for the years 2002 and 2003, and $16 million in total
thereafter. Excluded from these amounts is TGP's obligation to purchase 30
percent of the output of the Great Plains coal gasification project's original
design capacity through July 2009. In January 1997, TGP executed a settlement of
this contract as part of its GSR negotiations, recorded the related liability,
and, in the third quarter of 1997, purchased an annuity for $42 million to fund
the expected remaining monthly demand requirements of the contract which, under
the settlement, continue through January 2004.
 
  Operating Leases
 
     The Company leases certain property, facilities and equipment under various
operating leases. In addition, in 1995, El Paso New Chaco Company ("EPNC")
entered into an unconditional lease for the Chaco Plant. The lease term expires
in 2002, at which time EPNC has an option, and an obligation upon the occurrence
of certain events, to purchase the plant for a price sufficient to pay the
amount of the $77 million construction financing, plus interest and certain
expenses. If EPNC does not purchase the plant at the end of the lease term, it
has an obligation to pay a residual guaranty amount equal to approximately 87
percent of the amount financed, plus interest. EPEC and EPNG unconditionally
guaranteed all obligations of EPNC under the lease.
 
     Minimum annual rental commitments at December 31, 1998, were as follows:
 
<TABLE>
<CAPTION>
                     YEAR ENDING
                     DECEMBER 31,                       OPERATING LEASES
                     ------------                       ----------------
                                                         (IN MILLIONS)
<S>                                                     <C>
     1999.............................................        $ 7
     2000.............................................          6
     2001.............................................          6
     2002.............................................          5
     2003.............................................         --
     Thereafter.......................................         --
                                                              ---
     Total............................................        $24
                                                              ===
</TABLE>
 
     Rental expense for operating leases for the years ended December 31, 1998,
1997, and 1996 was $14 million, $11 million, and $11 million, respectively.
 
  Guarantees
 
     At December 31, 1998, EPTPC had guarantees of up to $37 million in
connection with various projects. EPEC has issued guarantees and letters of
credit associated with a number of the Company's projects including certain
international projects.
 
  Rates and Regulatory Matters
 
     In July 1998, FERC issued a Notice of Proposed Rulemaking ("NOPR") in which
it seeks comments on a wide range of initiatives to change the manner in which
short-term (less than one year) transportation markets are regulated. Among
other things, the NOPR proposes the following: (i) removing the price cap for
the short-term capacity market; (ii) establishing procedures to make pipeline
and shipper-owned capacity comparable; (iii) auctioning all available short-term
pipeline capacity on a daily basis with the pipeline unable to set a reserve
price above variable costs; (iv) changing policies or pipeline penalties,
nomination procedures and services; (v) increasing pipeline reporting
requirements; (vi) permitting the negotiation of terms and conditions of
service; and (vii) potentially modifying the procedures for certificating new
pipeline
 
                                       21
<PAGE>   26
 
construction. Also in July 1998, FERC issued a Notice of Inquiry ("NOI") seeking
comments on FERC's policy for pricing long-term capacity. Comments on the NOPR
and NOI are due in April 1999, and it is unclear when and what action, if any,
FERC will take in connection with the NOPR and NOI and the comments received in
response to them.
 
     In February 1997, TGP filed a settlement with FERC of all issues related to
the recovery of its GSR and other transition costs and related proceedings (the
"GSR Stipulation and Agreement"). In April 1997, FERC approved the settlement.
Under the terms of the GSR Stipulation and Agreement, TGP is entitled to collect
up to $770 million from its customers, $693 million through a demand surcharge
and $77 million through an interruptible transportation surcharge. As of
December 31, 1998, the demand portion had been fully collected and $41 million
of the interruptible transportation portion had been collected. There is no time
limit for collection of the interruptible transportation surcharge portion. The
terms of the GSR Stipulation and Agreement also provide for a rate case
moratorium through November 2000 (subject to certain limited exceptions) and an
escalating rate cap, indexed to inflation, through October 2005, for certain of
TGP's customers. Under the terms of the GSR Stipulation and Agreement, TGP is
required to refund to customers amounts collected in excess of each customer's
share of transition costs.
 
     In December 1994, TGP filed for a general rate increase with FERC and in
October 1996, FERC approved a settlement resolving that proceeding. The
settlement included a structural rate design change that results in a larger
portion of TGP's transportation revenues being dependent upon throughput. Under
the stipulation, TGP's refund obligation was approximately $185 million,
inclusive of interest, of which $161 million was refunded to customers in March
1997 and June 1997 with the remaining $24 million refund obligation offset
against GSR recoveries in accordance with particular customer elections. TGP
provided a reserve for these rate refunds as revenues were collected. One party,
a competitor of TGP, filed a Petition for Review of the FERC orders with the
Court of Appeals. The Court of Appeals remanded the case to FERC to respond to
the competitor's argument that TGP's cost allocation methodology deterred the
development of market centers (centralized locations where buyers and sellers
can physically exchange gas). At FERC's request, comments were filed in January
1999.
 
     All cost of service issues related to TGP's 1991 general rate proceeding
were resolved pursuant to a settlement agreement approved by FERC in an order
which now has become final. However, cost allocation and rate design issues
remained unresolved. In July 1996, following an ALJ's decision on these cost and
design issues, FERC ruled on certain issues but remanded to the ALJ the issue of
the proper allocation of TGP's New England lateral costs. In July 1997, FERC
issued an order denying rehearing of its July 1996 order but clarifying that,
among other things, although the ultimate resolution as to the proper allocation
of costs would be applied retroactively to July 1, 1995, the cost of service
settlement does not allow TGP to recover from other customers any amounts that
TGP may ultimately be required to refund. In February 1999, petitions for review
of the July 1996 and July 1997 FERC orders were denied by the Court of Appeals.
In the remand proceeding, the ALJ issued his decision on the proper allocation
of the New England lateral costs in December 1997. That decision adopts a
methodology that, economically, approximates the one currently used by TGP. In
October 1998, FERC issued an order affirming the ALJ's decision. Certain parties
have requested rehearing of that order, and the matter is currently pending
before FERC.
 
     TGP has filed cash out reports for the period September 1993 through August
1998. TGP's filings showed a cumulative loss through August of 1998 of $3
million. TGP has reached a settlement in principle with its customers to resolve
outstanding FERC proceedings related to these filed cash out reports. The
reports, as well as the accounting for customer imbalances, had been challenged
by TGP's customers. Upon FERC's approval, the settlement will provide for a new
mechanism for accounting for TGP's cash out program.
 
     Substantially all of the revenues of TGP are generated under long-term gas
transmission contracts. Contracts representing approximately 70 percent of TGP's
firm transportation capacity will be expiring over the next two years,
principally in November 2000. Although TGP cannot predict how much capacity will
be resubscribed, a majority of the expiring contracts cover service to
northeastern markets, where there is currently little excess capacity. Several
projects, however, have been proposed to deliver incremental volumes to these
markets. Although TGP is actively pursuing the renegotiation, extension and/or
replacement of these
 
                                       22
<PAGE>   27
 
contracts, there can be no assurance as to whether TGP will be able to extend or
replace these contracts (or a substantial portion thereof) or that the terms of
any renegotiated contracts will be as favorable to TGP as the existing
contracts.
 
  FERC Compliance Audits
 
     TGP, as an interstate pipeline, is subject to FERC audits of its books and
records. TGP does not have any open audits; however, TGP's property retirements
are currently under review by the FERC audit staff.
 
     Management believes the ultimate resolution of the aforementioned rate and
regulatory matters, which are in various stages of finalization, will not have a
material adverse effect on the Company's financial position, results of
operations, or cash flows.
 
  Legal Proceedings
 
     In February 1998, the United States and the State of Texas filed in a
United States District Court a Comprehensive Environmental Response,
Compensation and Liability Act cost recovery action, United States v. Atlantic
Richfield Co., et al., against fourteen companies including the following
affiliates of EPEC: TGP, EPTPC, EPEC Corporation, EPEC Polymers, Inc. and the
dissolved Petro-Tex Chemical Corporation, relating to the Sikes Disposal Pits
Superfund Site ("Sikes") located in Harris County, Texas. Sikes was an
unpermitted waste disposal site during the 1960s that accepted waste hauled from
numerous Houston Ship Channel industries. The suit alleges that the former
Tenneco Chemicals, Inc. and Petro-Tex Chemical Corporation arranged for disposal
of hazardous substances at Sikes. TGP, EPTPC, EPEC Corporation and EPEC
Polymers, Inc. are alleged to be derivatively liable as successors or as parent
corporations. The suit claims that the United States and the State of Texas have
expended over $125 million in remediating the site, and seeks to recover that
amount plus interest. Other companies named as defendants include Atlantic
Richfield Company, Crown Central Petroleum Corporation, Occidental Chemical
Corporation, Exxon Corporation, Goodyear Tire & Rubber Company, Rohm & Haas
Company, Shell Oil Company and Vacuum Tanks, Inc. These defendants have filed
their answers and third-party complaints seeking contribution from twelve other
entities believed to be PRPs at Sikes. Although factual investigation relating
to Sikes is in very preliminary stages, the Company believes that the amount of
material, if any, disposed at Sikes from the Tenneco Chemicals, Inc. or
Petro-Tex Chemical Corporation facilities was small, possibly de minimis.
However, the government plaintiffs have alleged that the defendants are each
jointly and severally liable for the entire remediation costs and have also
sought a declaration of liability for future response costs such as groundwater
monitoring. While the outcome of this matter cannot be predicted with certainty,
management does not expect this matter to have a material adverse effect on the
Company's financial position, results of operations, or cash flows.
 
     TGP is a party in proceedings involving federal and state authorities
regarding the past use by TGP of a lubricant containing PCBs in its starting air
systems. TGP has executed a consent order with the EPA governing the remediation
of certain of its compressor stations and is working with the relevant states
regarding those remediation activities. TGP is also working with the
Pennsylvania and New York environmental agencies to specify the remediation
requirements at the Pennsylvania and New York stations. Remediation activities
in Pennsylvania are complete with the exception of some long-term groundwater
monitoring requirements. Remediation and characterization work at the compressor
stations under its consent order with the EPA and the jurisdiction of the New
York Department of Environmental Conservation is ongoing. Management believes
that the ultimate resolution of these matters will not have a material adverse
effect on the Company's financial position, results of operations, or cash
flows.
 
     In November 1988, the Kentucky environmental agency filed a complaint in a
Kentucky state court, Commonwealth of Kentucky, Natural Resources and
Environmental Protection Cabinet v. Tennessee Gas Pipeline Company, alleging
that TGP discharged pollutants into the waters of the state without a permit and
disposed of PCBs without a permit. The agency sought an injunction against
future discharges, sought an order to remediate or remove PCBs, and sought a
civil penalty. TGP has entered into agreed orders with the agency to resolve
many of the issues raised in the original allegations, has received water
discharge permits for
 
                                       23
<PAGE>   28
 
its Kentucky compressor stations from the agency, and continues to work to
resolve the remaining issues. The relevant Kentucky compressor stations are
scheduled to be characterized and remediated under the consent order with the
EPA. Management believes that the resolution of this issue will not have a
material adverse effect on the Company's financial position, results of
operations, or cash flows.
 
     A number of subsidiaries of EPTPC, both wholly owned and partially owned,
have been named defendants in United States ex rel Grynberg v. El Paso Natural
Gas Company, et al. Generally, the complaint in this motion alleges an
industry-wide conspiracy to underreport the heating value as well as the volumes
of the natural gas produced from federal and Indian lands, thereby depriving the
U.S. government of royalties. The complaint remains sealed. The Company believes
the complaint to be without merit.
 
     The Company is a named defendant in numerous lawsuits and a named party in
numerous governmental proceedings arising in the ordinary course of business.
While the outcome of such lawsuits or other proceedings against the Company
cannot be predicted with certainty, management currently does not expect these
matters to have a material adverse effect on the Company's financial position,
results of operations, or cash flows.
 
ENVIRONMENTAL
 
     The Company is subject to extensive federal, state, and local laws and
regulations governing environmental quality and pollution control. These laws
and regulations require the Company to remove or remedy the effect on the
environment of the disposal or release of specified substances at current and
former operating sites. As of December 31, 1998, the Company had reserves for
expected remediation costs and associated onsite, offsite and groundwater
technical studies of approximately $138 million; and other costs of
approximately $8 million which the Company anticipates incurring through 2027.
 
     In addition, the Company estimates that its subsidiaries will make capital
expenditures for environmental matters of approximately $6 million in 1999.
Capital expenditures will range from approximately $51 million to $76 million in
the aggregate for the years 2000 through 2007. These expenditures primarily
relate to compliance with air regulations and, to a lesser extent, control of
water discharges.
 
     Since 1988, TGP has been engaged in an internal project to identify and
deal with the presence of PCBs and other substances of concern, including
substances on the EPA List of Hazardous Substances, at compressor stations and
other facilities operated by both its interstate and intrastate natural gas
pipeline systems. While conducting this project, TGP has been in frequent
contact with federal and state regulatory agencies, both through informal
negotiation and formal entry of consent orders, to assure that its efforts meet
regulatory requirements.
 
     In May 1995, following negotiations with its customers, TGP filed with FERC
a separate Stipulation and Agreement (the "Environmental Stipulation") that
establishes a mechanism for recovering a substantial portion of the
environmental costs identified in the internal project. In November 1995, FERC
issued an order approving the Environmental Stipulation. Although one shipper
filed for rehearing, FERC denied rehearing of its order in February 1996. The
Environmental Stipulation was effective July 1, 1995. As of
December 31, 1998, a balance of $2 million remains to be collected under the
stipulation.
 
     The Company and certain of its subsidiaries have been designated, have
received notice that they could be designated, or have been asked for
information to determine whether they could be designated as a PRP with respect
to 11 sites under the Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA or Superfund) or state equivalents. The Company has sought
to resolve its liability as a PRP with respect to these Superfund sites through
indemnification by third parties and/or settlements which provide for payment of
the Company's allocable share of remediation costs. As of December 31, 1998, the
Company has estimated its share of the remediation costs at these sites to be
between $3 million and $6 million and has provided reserves that it believes are
adequate for such costs. Since the clean-up costs are estimates and are subject
to revision as more information becomes available about the extent of
remediation required, and because in some cases the Company has asserted a
defense to any liability, the Company's estimate of its
 
                                       24
<PAGE>   29
 
share of remediation costs could change. Moreover, liability under the federal
Superfund statute is joint and several, meaning that the Company could be
required to pay in excess of its pro rata share of remediation costs. The
Company's understanding of the financial strength of other PRPs has been
considered, where appropriate, in its determination of its estimated liability
as described herein. The Company presently believes that the costs associated
with the current status of such entities as PRPs at the Superfund sites
referenced above will not have a material adverse effect on the Company's
financial position, results of operations, or cash flows.
 
     The Company has initiated proceedings against its historic liability
insurers seeking payment or reimbursement of costs and liabilities associated
with environmental matters. In these proceedings, the Company contends that
certain environmental costs and liabilities associated with various entities or
sites, including costs associated with former operating sites, must be paid or
reimbursed by certain of its historic insurers. The proceedings are in the
discovery stage, and it is not yet possible to predict the outcome.
 
     It is possible that new information or future developments could require
the Company to reassess its potential exposure related to environmental matters.
The Company may incur significant costs and liabilities in order to comply with
existing environmental laws and regulations. It is also possible that other
developments, such as increasingly strict environmental laws, regulations and
enforcement policies thereunder, and claims for damages to property, employees,
other persons and the environment resulting from current or discontinued
operations, could result in substantial costs and liabilities in the future. As
such information becomes available, or developments occur, related accrual
amounts will be adjusted accordingly. While there are still uncertainties
relating to the ultimate costs which may be incurred, based upon the Company's
evaluation and experience to date, the Company believes the recorded reserve is
adequate.
 
     For a further discussion of specific environmental matters, see Legal
Proceedings above.
 
OTHER
 
  PPN Power Project
 
     In March 1999, the Company signed a sale and purchase agreement to acquire
a 26 percent interest in a $295 million power plant in Tamil Nadu, India. The
project consists of a 346 MW combined cycle power plant which will serve as a
base load facility and sell power to the state-owned Tamil Nadu Electricity
Board under a thirty-year power purchase agreement. Construction began in
January 1999, and operations are expected to commence in early 2001. Transfer of
the funds to complete the acquisition is expected to be finalized by the end of
March 1999.
 
  Year 2000
 
     EPEC has established an executive steering committee and a project team to
coordinate the phases of its Year 2000 project to assure that the Company's key
automated systems and related processes will remain functional through the year
2000. Those phases are: (i) awareness; (ii) assessment; (iii) remediation; (iv)
testing; (v) implementation of the necessary modifications and (vi) contingency
planning (which was previously included as a component of EPEC's implementation
phase). The Company has participated in EPEC's Year 2000 project as described
below.
 
     In recognition of the importance of Year 2000 issues and their potential
impact to EPEC, the initial phase of the Year 2000 project involved the
establishment of a company-wide awareness program. The awareness program is
directed by the executive steering committee and project team and includes
participation of senior management in each core business area. The awareness
phase is substantially completed, although EPEC will continually update
awareness efforts for the duration of the Year 2000 project.
 
     The Company's assessment phase consists of conducting a company-wide
inventory of its key automated systems and related processes, analyzing and
assigning levels of criticality to those systems and processes, identifying and
prioritizing resource requirements, developing validation strategies and testing
plans, and evaluating business partner relationships. The portion of the
assessment phase related to internally developed computer applications, hardware
and equipment, and embedded chips is substantially complete. The
 
                                       25
<PAGE>   30
 
Company estimates that it has finished more than three-fourths of the portion of
the assessment to determine the nature and impact of the Year 2000 date change
for third-party-developed software. The assessment phase of the project, among
other things, involves efforts to obtain representations and assurances from
third parties, including third party vendors, that their hardware and equipment
products, embedded chip systems, and software products being used by or
impacting the Company are or will be modified to be Year 2000 compliant. To
date, the responses from such third parties, although generally encouraging, are
inconclusive. As a result, the Company cannot predict the potential consequences
if these or other third parties or their products are not Year 2000 compliant.
The Company is currently evaluating the exposure associated with such business
partner relationships.
 
     The remediation phase involves converting, modifying, replacing or
eliminating key automated systems identified in the assessment phase. The
testing phase involves the validation of the identified key automated systems.
The Company is utilizing test tools and written test procedures to document and
validate, as necessary, its unit, system, integration, and acceptance testing.
The Company estimates that approximately one-half of the work of these phases
remains, and expects each to be substantially completed by mid-1999.
 
     The implementation phase involves placing the converted or replaced key
automated systems into operation. In some cases, this phase will also involve
the implementation of contingency plans needed to support business functions and
processes that may be interrupted by Year 2000 failures that are outside of the
Company's control. The Company has completed more than one-fourth of the
implementation phase, which is expected to be substantially completed by
mid-1999.
 
     The contingency planning phase consists of developing a risk profile of the
Company's critical business processes and then providing for actions the Company
will pursue to keep such processes operational in the event of Year 2000
disruptions. The focus of such contingency planning is on prompt response to any
Year 2000 events, and a plan for subsequent resumption of normal operations. The
plan is expected to assess the risk of a significant failure to critical
processes performed by the Company, and to address the mitigation of those
risks. The plan will also consider any significant failures related to the most
reasonably likely worst case scenario, discussed below, as they may occur. In
addition, the plan is expected to factor in the severity and duration of the
impact of a significant failure. The Company plans to have its contingency plan
completed by mid-1999. The Year 2000 contingency plan will continue to be
modified and adjusted throughout the year as additional information becomes
available.
 
     The goal of the Year 2000 project is to ensure that all of the critical
systems and processes which are under the Company's direct control remain
functional. Certain systems and processes may be interrelated with or dependent
upon systems outside the Company's control, however, and systems within the
Company's control may have unpredicted problems. Accordingly, there can be no
assurance that significant disruptions will be avoided. The Company's present
analysis of its most reasonably likely worst case scenario for Year 2000
disruptions includes Year 2000 failures in the telecommunications and
electricity industries, as well as interruptions from suppliers that might cause
disruptions in the Company's operations, thus causing temporary financial losses
and an inability to deliver products and services to customers. Virtually all of
the natural gas transported through the Company's interstate pipelines is owned
by third parties. Accordingly, failures of natural gas producers to be ready for
the Year 2000 could significantly disrupt the flow of product to the Company's
customers. In many cases, the producers have no direct contractual relationship
with the Company, and the Company relies on its customers to verify the Year
2000 readiness of the producers from whom they purchase natural gas. Since most
of the Company's revenues from the delivery of natural gas are based upon fees
paid by its customers for the reservation of capacity, and not based upon the
volume of actual deliveries, short term disruptions in deliveries caused by
factors beyond the Company's control should not have a significant financial
impact on the Company, although it could cause operational problems for the
Company's customers. Longer-term disruptions, however, could materially impact
the Company's results of operations, financial condition, and cash flows.
 
     While the Company owns or controls most of its domestic facilities and
projects, nearly all of the Company's international investments have been made
in conjunction with unrelated third parties. In many cases, the operators of
such international facilities are not under the sole or direct control of the
Company. As
 
                                       26
<PAGE>   31
 
a consequence, the Year 2000 programs instituted at some of the international
facilities may be different from the Year 2000 program implemented by the
Company domestically, and the party responsible for the results of such program
may not be under the direct or indirect control of the Company. In addition, the
"non-controlled" programs may not provide the same degree of communication,
documentation and coordination as the Company achieves in its domestic Year 2000
program. Moreover, the regulatory and legal environment in which such
international facilities operate makes analysis of possible disruption and
associated financial impact difficult. Many foreign countries appear to be
substantially behind the United States in addressing potential Year 2000
disruption of critical infrastructure and in developing a framework governing
the reporting requirements and relative liabilities of business entities.
Accordingly, the Year 2000 risks posed by international operations as a whole
are different than those presented domestically. As part of its Year 2000
effort, the Company is assessing the differences between the non-controlled
programs and its domestic Year 2000 project, and has formulated and instituted a
program for identifying such risks and preparing a response to such risks. While
the Company believes that most of the international facilities in which it has
significant investments are addressing Year 2000 issues in an adequate manner,
it is possible that some of them may experience significant Year 2000
disruption, and that the aggregate effect of problems experienced at multiple
international locations may be material and adverse. The Company intends to
incorporate this possibility into the relevant contingency plans.
 
     While the total cost of the Company's Year 2000 project is still being
evaluated, the Company estimates that the costs to be incurred in 1999 and 2000
associated with assessing, remediating and testing internally developed computer
applications, hardware and equipment, embedded chip systems, and
third-party-developed software will be between $10 million and $19 million. Of
these estimated costs, the Company expects between $5 million and $11 million to
be capitalized and the remainder to be expensed. As of December 31, 1998, the
Company has incurred expenses of approximately $6 million. The Company has
previously only traced incremental expenses related to its Year 2000 project.
This means that the costs of the Year 2000 project related to salaried employees
of the Company, including their direct salaries and benefits, are not available,
and have not been included in the estimated costs of the project. Since the
earlier phases of the project mostly involved work performed by such salaried
employees, the costs expended to date do not reflect the percentage completion
of the project. The Company anticipates that it will expend most of the costs
reported above in the remediation, implementation and contingency planning
phases of the project. It is possible the Company may need to reassess its
estimate of Year 2000 costs in the event the Company completes an acquisition
of, or makes a material investment in, substantial facilities or another
business entity.
 
     Although the Company does not expect the costs of its Year 2000 project to
have a material adverse effect on its financial position, results of operations,
or cash flows, based on information available at this time the Company cannot
conclude that disruption caused by internal or external Year 2000 related
failures will not have such an effect. Specific factors which might affect the
success of the Company's Year 2000 efforts and the occurrence of Year 2000
disruption or expense include the failure of the Company of its outside
consultants to properly identify deficient systems, the failure of the selected
remedial action to adequately address the deficiencies, the failure of the
Company's outside consultants to complete the remediation in a timely manner
(due to shortages of qualified labor or other factors), unforeseen expenses
related to the remediation of existing systems or the transition to replacement
systems, the failure of third parties to become Year 2000 compliant or to
adequately notify the Company of potential noncompliance and the effects of any
significant disruption at international facilities in which the Company has
significant investments.
 
     The above disclosure is a "YEAR 2000 READINESS DISCLOSURE" made with the
intention to comply fully with the Year 2000 Information and Readiness
Disclosure Act of 1998, Pub. L. No. 105-271, 112 Stat, 2386, signed into law
October 19, 1998. All statements made herein shall be construed within the
confines of that Act. To the extent that any reader of the above Year 2000
Readiness Disclosure is other than an investor or potential investor in the
Company's -- or an affiliate's -- equity or debt securities, this disclosure is
made for the SOLE PURPOSE of communicating or disclosing information aimed at
correcting, helping to correct and/or avoid Year 2000 failures.
 
     Management is not aware of other commitments or contingent liabilities
which would have a materially adverse effect on the Company's financial
condition, results of operations, or cash flows.
                                       27
<PAGE>   32
 
                 NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
 
  Accounting for the Costs of Computer Software Developed or Obtained for
Internal Use
 
     In March 1998, the American Institute of Certified Public Accountants
issued Statement of Position 98-1, Accounting for the Costs of Computer Software
Developed or Obtained for Internal Use. This statement provides guidance on
accounting for such costs, and also defines internal-use computer software. The
statement is effective for fiscal years beginning after December 15, 1998. The
application of this pronouncement will not have a material impact on the
Company's financial position, results of operations, or cash flows.
 
  Reporting on the Costs of Start-Up Activities
 
     In April 1998, the American Institute of Certified Public Accountants
issued Statement of Position 98-5, Reporting on the Costs of Start-Up
Activities. The statement defines start-up activities and requires start-up and
organization costs to be expensed as incurred. In addition, it requires that any
such cost that exists on the balance sheet be expensed upon adoption of this
pronouncement. The statement is effective for fiscal years beginning after
December 15, 1998. The Company will adopt this pronouncement effective January
1, 1999, and expects to report a charge in the range of $7 million to $12
million, net of income taxes, in the first quarter of 1999 as a cumulative
effect of a change in accounting principle.
 
  Accounting for Derivative Instruments and Hedging Activities
 
     In June 1998, SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities, was issued by the Financial Accounting Standards Board to
establish accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities. SFAS No. 133 requires that an entity classify all
derivatives as either assets or liabilities in the statement of financial
position and measure those instruments at fair value. If certain conditions are
met, a derivative may be specifically designated as (i) a hedge of the exposure
to changes in the fair value of a recognized asset or liability or an
unrecognized firm commitment, (ii) a hedge of the exposure to variable cash
flows of a forecasted transaction, or (iii) a hedge of the foreign currency
exposure of a net investment in a foreign operation, an unrecognized firm
commitment, an available-for-sale security, or a foreign-currency-denominated
forecasted transaction. The accounting for the changes in the fair value of a
derivative depends on the intended use of the derivative and the resulting
designation. The standard is effective for all quarters in fiscal years
beginning after June 15, 1999. The Company is currently evaluating the effects
of this pronouncement.
 
  Disclosure relating to Euro Conversion
 
     In July 1998, the Securities and Exchange Commission issued Staff Legal
Bulletin No. 6 to provide guidance for disclosure related to the Euro
Conversion. The guidance primarily focuses on disclosure in the Management's
Discussion and Analysis of Financial Condition and Results of Operations, as
well as Description of Business. The Company currently has no investments in the
countries affected by the Euro Conversion.
 
  Accounting for Contracts Involved in Energy Trading and Risk Management
Activities
 
     In November 1998, the Emerging Issues Task Force reached a consensus on
EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk
Management Activities. EITF 98-10 requires energy trading contracts to be
recorded at fair value on the balance sheet, with the changes in fair value
included in earnings. EITF 98-10 is effective for fiscal years beginning after
December 15, 1998. The Company adopted the provisions of EITF 98-10 in January
1999. The application of this pronouncement did not have a material impact on
the Company's financial position, results of operations, or cash flows.
 
                                       28
<PAGE>   33
 
            RISK FACTORS -- 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 such forward-looking statement includes a statement of the
assumptions or bases underlying such forward-looking statement, we caution that,
while such assumptions or bases are believed to be reasonable and are made in
good faith, assumed facts or bases almost always vary from the actual results,
and the differences between assumed facts or bases and actual results can be
material, depending upon the circumstances. Where, in any forward-looking
statement, we or our management express an expectation or belief as to future
results, such expectation or belief is expressed in good faith and is believed
to have a reasonable basis, but there can be no assurance that the statement of
expectation or belief will result or be achieved or accomplished. The words
"believe," "expect," "estimate," "anticipate" and similar expressions may
identify forward-looking statements.
 
     With this in mind, you should consider the following important factors that
could cause actual results to differ materially from those expressed in any
forward-looking statement made by us or on our behalf:
 
OUR INDUSTRY IS HIGHLY COMPETITIVE
 
     The hydrocarbons that we transport, gather, process and store are owned by
third parties. As a result, the volume of hydrocarbons involved in such
activities is dependent upon the actions of those third parties, and are beyond
our control. Further, our ability to maintain or increase current transmission,
gathering, processing, and sales volumes or to remarket unsubscribed capacity,
is subject to the impact of the following:
 
     - future weather conditions or other alternative energy sources;
 
     - price competition;
 
     - drilling activity and supply availability; and
 
     - service competition.
 
     Our future profitability may be affected by our ability to compete with the
services offered by other energy enterprises which may be larger, offer more
services, and possess greater resources.
 
     Seventy percent of TGP's contracts are expiring over the next two years,
principally in November 2000. Our ability to negotiate new contracts and to
renegotiate existing contracts could be adversely affected by factors we cannot
control, including:
 
     - the proposed construction by other companies of additional pipeline
       capacity in the markets served by TGP;
 
     - reduced demand due to higher gas prices;
 
     - the availability of alternative energy sources; and
 
     - the viability of our expansion projects.
 
     For a further discussion see Item 1, Business, Markets and Competition.
 
FLUCTUATIONS IN NATURAL GAS AND NATURAL GAS LIQUIDS PRICES COULD ADVERSELY
AFFECT OUR BUSINESS
 
     Our ability to compete with other transporters is impacted by natural gas
prices in the supply basins connected to our pipeline systems as compared to
prices in other gas producing regions, especially Canada. Revenues generated by
our gathering and processing contracts are dependent upon volumes and rates,
both of which can be affected by the prices of natural gas and natural gas
liquids. The success of our expanding gathering and processing operations in the
offshore Gulf of Mexico is subject to continued development of additional oil
and gas reserves in the vicinity of our facilities and our ability to access
such additional reserves to offset the natural decline from existing wells
connected to our systems. A decline in energy prices could
 
                                       29
<PAGE>   34
 
precipitate a decrease in such development activities and could cause a decrease
in the volume of reserves available for gathering and processing through our
offshore facilities. Fluctuations in energy prices, which may impact gathering
rates and investments by third parties in the development of new oil and gas
reserves connected to our gathering and processing facilities, are caused by a
number of factors, including:
 
     - regional, domestic and international supply and demand;
 
     - availability and adequacy of transportation facilities;
 
     - energy legislation;
 
     - federal or state taxes, if any, on the sale or transportation of natural
       gas and natural gas liquids and the price; and
 
     - abundance of supplies of alternative energy sources.
 
If there are reductions in the average volume of the natural gas we transport,
gather and process for a prolonged period, our results of operations and
financial position could be materially adversely affected.
 
THE USE OF DERIVATIVE FINANCIAL INSTRUMENTS COULD RESULT IN FINANCIAL LOSSES
 
     Some of our non-regulated subsidiaries are engaged in the gathering,
processing and marketing of natural gas and other energy commodities and utilize
futures and option contracts traded on the New York Mercantile Exchange and
over-the-counter options and price and basis swaps with other gas merchants and
financial institutions. These instruments are intended to reduce our exposure to
short-term volatility in changes in commodities prices. We could, however, incur
financial losses in the future as a result of volatility in the market values of
the underlying commodities or if one of our counterparties fails to perform
under a contract. For additional information concerning our derivative financial
instruments, see item 7A, Quantitative and Qualitative Disclosures About Market
Risks and Item 8, Financial Statements and Supplementary Data, Note 4.
 
ATTRACTIVE ACQUISITION AND INVESTMENT OPPORTUNITIES MAY NOT BE AVAILABLE
 
     Our ability to grow will depend, in part, upon our ability to identify and
complete attractive acquisition and investment opportunities. Opportunities for
growth through acquisitions and investments in joint ventures, and the future
operating results and success of such acquisitions and joint ventures within and
outside the U.S. may be subject to the effects of, and changes in the following:
 
     - U.S. and foreign trade and monetary policies;
 
     - laws and regulations;
 
     - political and economic developments;
 
     - inflation rates;
 
     - taxes; and
 
     - operating conditions.
 
OUR FOREIGN INVESTMENTS INVOLVE SPECIAL RISKS
 
     Our activities in areas outside the U.S. are subject to the risks inherent
in foreign operations, including:
 
     - loss of revenue, property and equipment as a result of hazards such as
       expropriation, nationalization, wars, insurrection and other political
       risks, and
 
     - the effects of currency fluctuations and exchange controls (such as the
       recent devaluation of the Indonesian and Brazilian currencies and other
       economic problems).
 
                                       30
<PAGE>   35
 
Such legal and regulatory events and other unforeseeable obstacles may be beyond
our control or ability to manage.
 
WE COULD INCUR SUBSTANTIAL ENVIRONMENTAL LIABILITIES
 
     We may incur significant costs and liabilities in order to comply with
existing environmental laws and regulations. It is also possible that other
developments, such as increasingly strict environmental laws, regulations and
enforcement policies thereunder, and claims for damages to property, employees,
other persons and the environment resulting from current or discontinued
operations, could result in substantial costs and liabilities in the future. For
additional information concerning the Company's environmental matters, see the
section of this item entitled "Environmental."
 
OUR ACTIVITIES INVOLVE OPERATING HAZARDS AND UNINSURED RISKS
 
     While we maintain insurance against certain of the risks normally
associated with the transportation, gathering and processing of natural gas,
including explosions, pollution and fires, the occurrence of a significant event
that is not fully insured against could have a material adverse effect on our
business.
 
THERE REMAIN POTENTIAL LIABILITIES RELATED TO THE ACQUISITION OF EPTPC
 
     The amount of the actual and contingent liabilities of EPTPC, which
remained the liabilities of EPEC after the acquisition by EPEC of EPTPC, could
vary materially from the amount we estimated, which was based upon assumptions
which could prove to be inaccurate. If New Tenneco or Newport News Shipbuilding
Inc. were unable or unwilling to pay their respective liabilities, a court could
require us, under certain legal theories which may or may not be applicable to
the situation, to assume responsibility for such obligations. If we were
required to assume these obligations, it could have a material adverse effect on
our financial condition, results of operations or cash flows.
 
THERE REMAIN POTENTIAL FEDERAL INCOME TAX LIABILITIES RELATED TO THE ACQUISITION
OF EPTPC
 
     In connection with the acquisition by EPEC of EPTPC and distributions made
by EPTPC prior to that acquisition, the IRS issued a private letter ruling to
Old Tenneco, in which it ruled that for U.S. federal income tax purposes the
Distributions would be tax-free to Old Tenneco and, except to the extent cash
was received in lieu of fractional shares, to its then existing stockholders;
the acquisition by EPEC would constitute a tax-free reorganization; and that
certain other transactions effected in connection with the acquisition by EPEC
would be tax-free. If the distributions were not to qualify as tax-free
distributions, then a corporate level federal income tax would be assessed to
the consolidated group of which Old Tenneco was the common parent. This
corporate level federal income tax would be payable by EPTPC. Under certain
limited circumstances, however, New Tenneco and Newport News Shipbuilding Inc.
have agreed to indemnify EPTPC for a defined portion of such tax liabilities.
 
WE ARE SUBJECT TO FINANCING AND INTEREST RATE EXPOSURE RISKS
 
     Our business and operating results can be adversely affected by factors
such as the availability or cost of capital, changes in interest rates, changes
in the tax rates due to new tax laws, market perceptions of the natural gas
industry or EPEC, or credit ratings.
 
WE ARE SUBJECT TO RISKS ASSOCIATED WITH YEAR 2000 ISSUES
 
     We are taking steps to mitigate any adverse effects of the Year 2000 date
change on our customers and business operations including the assessment,
remediation, testing of our applications, hardware and software, and the
implementation of necessary change. Nevertheless, our failure, or the failure of
third-parties with whom we deal, to achieve Year 2000 compliance may adversely
affect our business. For additional information on our Year 2000 strategy and
specific factors that may affect our ability to achieve Year 2000 compliance,
see the section of this item entitled "Other -- Year 2000."
 
                                       31
<PAGE>   36
 
ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
     The Company utilizes derivative financial instruments to manage market
risks associated with certain energy commodities and interest and foreign
currency exchange rates. The Company's primary market risk exposure is to
changing commodity prices. Market risks are monitored by a corporate risk
management committee that operates independently from the business segments that
create or actively manage these risk exposures to ensure compliance with the
Company's stated risk management policies as approved by EPEC's Board of
Directors. These policies are set forth in Item 8, Financial Statements and
Supplementary Data, Note 1.
 
TRADING COMMODITY PRICE RISK
 
     EPEM is exposed to certain market risks inherent in its financial
instruments entered into for trading purposes associated with natural gas, power
and petroleum products. EPEM marks to market all energy trading activities,
including transportation capacity and storage. EPEM's policy is to manage
commodity price risk through a variety of financial instruments, including
forward contracts involving cash settlements or physical delivery of an energy
commodity, swap contracts which require payment to (or receipts from)
counterparties based on the differential between a fixed and variable price for
the commodity, exchange-traded options, over-the-counter options and other
contractual arrangements. EPEM manages market risk on a portfolio basis, subject
to parameters established by the risk management committee. Comprehensive risk
management processes, policies, and procedures have been established to monitor
and control its market risk. The Company's risk management committee also
continually reviews these policies to ensure they are responsive to changing
business conditions.
 
     EPEM measures the risk in its commodity and energy related contract
portfolio on a daily basis utilizing a Value-at-Risk ("VAR") model to determine
the maximum potential one-day unfavorable impact on its earnings from its
existing portfolio due to normal market movements and monitors its risk in
comparison to established thresholds. The VAR computations are based on
historical simulation, which utilizes price movements over a specified period to
simulate forward price curves in the energy markets, and several key
assumptions, including the selection of a confidence level for expected losses
and the holding period for liquidation. EPEM also utilizes other measures
outside the VAR methodology to monitor the risk in its commodity and energy
related contract portfolio on a monthly basis, including stress testing,
position limit control and credit, liquidity and event risk management. EPEM
previously utilized sensitivity analysis to report market risk based on a ten
percent change in commodity prices. The uncertainty of the market place,
increased trading of derivative instruments, and the complexity of these
instruments created the demand for a more comprehensive portfolio level
quantitative measure of market risk. Accordingly, EPEM converted from utilizing
sensitivity analysis to the VAR model during 1998.
 
     Assuming a confidence level of 95 percent and a one-day holding period,
EPEM's estimated potential one-day unfavorable impact on income before income
taxes, as measured by VAR, related to its commodity and energy related contracts
held for trading purposes was approximately $2 million as of December 31, 1998,
and 1997. VAR was implemented on April 1, 1998, therefore volatilities and
correlations applicable on April 1, 1998, were used to provide comparative data
for December 31, 1997. Actual losses could exceed those measured by VAR.
 
NON-TRADING COMMODITY PRICE RISK
 
     The estimated potential one-day unfavorable impact on income before income
taxes and minority interest, as measured by VAR, related to EPEM's non-trading
commodity activities was immaterial at December 31, 1998, and 1997.
 
NON-TRADING INTEREST RATE RISK
 
     The Company's debt financial instruments are sensitive to market
fluctuations in interest rates. The table below presents principal cash flows
and related weighted average interest rates by expected maturity dates. As of
December 31, 1998, and 1997, the carrying amounts of short-term borrowings are
representative of fair
                                       32
<PAGE>   37
 
values because of the short-term maturity of these instruments. The fair value
of the long-term debt has been estimated based on quoted market prices for the
same or similar issues.
 
     The Company's equity swap is also sensitive to market fluctuations in
interest rates. In March 1997, the Company purchased a 10.5 percent interest in
CAPSA for approximately $57 million. In connection with this acquisition, the
Company entered into an equity swap transaction associated with an additional
18.5 percent of CAPSA's then outstanding stock. Under the equity swap, the
Company pays interest to the counterparty, on a quarterly basis, on a notional
amount of $100 million at a rate of LIBOR plus 0.85 percent. In exchange, the
Company receives dividends on the CAPSA stock to the extent of the
counterparty's equity interest of 18.5 percent. In February 1999, the Company
extended the term of the swap for two and a half years. For the equity swap, the
table below presents the notional amount and weighted average interest rate by
expected or contractual maturity dates. The notional amount is used to calculate
the contractual payments to be exchanged under the contract. The fair value of
the derivative financial instrument is the estimated amount at which management
believes it could be liquidated over a reasonable period of time, based on
quoted market prices, current market conditions, or other estimates obtained
from third-party dealers.
 
     The tabular presentation related to activities other than commodity
trading, as of December 31, 1998, and 1997, is illustrated below:
 
<TABLE>
<CAPTION>
                                                                  DECEMBER 31, 1998
                                         -------------------------------------------------------------------
                                                          EXPECTED FISCAL YEAR OF MATURITY
                                         -------------------------------------------------------------------
                                         1999   2000   2001   2002   2003   THEREAFTER   TOTAL    FAIR VALUE
                                         ----   ----   ----   ----   ----   ----------   ------   ----------
                                                                (DOLLARS IN MILLIONS)
<S>                                      <C>    <C>    <C>    <C>    <C>    <C>          <C>      <C>
LIABILITIES:
  Short-term debt -- variable rate.....  $190                                            $  190     $  190
  ------------------------------------
       Average interest rate...........   5.8%
  Long-term debt, including
  -----------------------------
     current portion -- fixed rate.....  $  4   $  9   $ 40   $ 12            $1,406     $1,471     $1,563
     ----------------------------------
       Average interest rate...........   6.5%   7.0%   6.5%   6.5%              7.5%
INTEREST RATE DERIVATIVES:
  Equity swap
  --------------
     Interest to dividend -- notional
       amount..........................  $100                                            $  100     $    3
       Average interest rate(a)........   6.5%
       Received dollars(b).............    --
       Net cash flow effect............  $ (7)
</TABLE>
 
<TABLE>
<CAPTION>
                                                                DECEMBER 31, 1997
                                                              ---------------------
                                                               TOTAL    FAIR VALUE
                                                              -------   -----------
                                                              (DOLLARS IN MILLIONS)
<S>                                                           <C>       <C>
LIABILITIES:
  Short-term debt -- variable rate..........................  $  417      $  417
     Average interest rate paid in 1998.....................     6.0%
  Long-term debt, including current portion -- fixed rate...  $1,128      $1,199
       Average interest rate paid in 1998...................     7.4%
INTEREST RATE DERIVATIVES:
  Equity swap
     Interest to dividend -- notional amount................  $  100      $    8
       Average interest rate paid in 1998(a)................     6.6%
       Received dollars in 1998(b)..........................      --
       Net cash flow effect for 1998........................  $   (7)
</TABLE>
 
---------------
 
(a) The variable rates presented are the average forward rates for the remaining
    term of each contract.
 
(b) The Company receives dividends, to the extent paid, on the CAPSA stock to
    the extent of the counterparty's equity interest of 18.5 percent. No
    dividends were received in 1998 and no dividends are expected for 1999.
 
                                       33
<PAGE>   38
 
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
                         EL PASO TENNESSEE PIPELINE CO.
 
                       CONSOLIDATED STATEMENTS OF INCOME
                                 (IN MILLIONS)
 
<TABLE>
<CAPTION>
                                                                YEAR ENDED DECEMBER 31,
                                                              ----------------------------
                                                               1998       1997       1996
                                                              ------     ------     ------
<S>                                                           <C>        <C>        <C>
Operating revenues
  Transportation............................................  $  713     $  737     $  681
  Natural gas, liquids and power............................   4,370      4,111      3,968
  Gathering and processing..................................     141        204        126
  Other.....................................................      84         65        233
                                                              ------     ------     ------
                                                               5,308      5,117      5,008
                                                              ------     ------     ------
Operating expenses
  Cost of gas and other products............................   4,215      4,122      3,869
  Operation and maintenance.................................     480        465        580
  Finance charges...........................................      --         --         62
  Depreciation, depletion and amortization..................     201        177        194
  Taxes, other than income taxes............................      55         62         64
                                                              ------     ------     ------
                                                               4,951      4,826      4,769
                                                              ------     ------     ------
Operating income............................................     357        291        239
                                                              ------     ------     ------
Other (income) and expense
  Interest and debt expense.................................     152        141        151
  Gain on sale of assets, net...............................     (19)        (1)       (35)
  Other, net................................................     (95)       (52)       (83)
                                                              ------     ------     ------
                                                                  38         88         33
                                                              ------     ------     ------
Income before income taxes..................................     319        203        206
Income tax expense..........................................      94         73         43
                                                              ------     ------     ------
Income before extraordinary loss............................     225        130        163
Extraordinary loss, net of income tax.......................      --         --       (234)
                                                              ------     ------     ------
Net income (loss)...........................................  $  225     $  130     $  (71)
                                                              ======     ======     ======
</TABLE>
 
              The accompanying Notes are an integral part of these
                       Consolidated Financial Statements.
                                       34
<PAGE>   39
 
                         EL PASO TENNESSEE PIPELINE CO.
 
                          CONSOLIDATED BALANCE SHEETS
                      (IN MILLIONS, EXCEPT SHARE AMOUNTS)
 
<TABLE>
<CAPTION>
                                                                 DECEMBER 31,
                                                              ------------------
                                                               1998        1997
                                                              ------      ------
<S>                                                           <C>         <C>
                                     ASSETS
Current assets
  Cash and temporary investments............................  $   28      $   35
  Accounts and notes receivable, net
     Customer...............................................     266         669
     Affiliated companies...................................      62          --
     Other..................................................     166         240
  Inventories...............................................      21          41
  Deferred income taxes.....................................      75         121
  Assets from price risk management activities..............     151          96
  Regulatory assets.........................................       9         116
  Prepaid expenses..........................................      16          21
  Other.....................................................      18          42
                                                              ------      ------
          Total current assets..............................     812       1,381
                                                              ------      ------
Plant, property and equipment, net..........................   5,749       5,509
Investment in unconsolidated affiliates.....................     579         373
Other.......................................................     386         300
                                                              ------      ------
          Total assets......................................  $7,526      $7,563
                                                              ======      ======
 
                      LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
  Accounts payable
     Trade..................................................  $  404      $  732
     Affiliated companies...................................     744         438
     Other..................................................     113          72
  Short-term borrowings (including current maturities on
     long-term debt)........................................     194         463
  Note payable to EPEC......................................      35         125
  Accrual for regulatory issues.............................      13          --
  Liabilities from price risk management activities.........     102          73
  Other.....................................................     352         464
                                                              ------      ------
          Total current liabilities.........................   1,957       2,367
                                                              ------      ------
Long-term debt, less current maturities.....................   1,467       1,082
                                                              ------      ------
Deferred income taxes.......................................   1,277       1,378
                                                              ------      ------
Postretirement benefits.....................................     245         281
                                                              ------      ------
Other.......................................................     362         477
Minority interest...........................................      65          65
                                                              ------      ------
Commitments and contingencies (See Note 5)
Stockholders' equity
  Preferred stock, 20,000,000 shares authorized;
     Series A, no par; 6,000,000 shares issued; stated at
      liquidation value.....................................     300         300
  Common stock, par value $.01 per share; authorized 100,000
     shares; issued 1,971 shares............................      --          --
  Additional paid-in capital................................   1,540       1,489
  Retained earnings.........................................     327         131
  Accumulated comprehensive income..........................     (14)         (7)
                                                              ------      ------
          Total stockholders' equity........................   2,153       1,913
                                                              ------      ------
          Total liabilities and stockholders' equity........  $7,526      $7,563
                                                              ======      ======
</TABLE>
 
              The accompanying Notes are an integral part of these
                       Consolidated Financial Statements.
                                       35
<PAGE>   40
 
                         EL PASO TENNESSEE PIPELINE CO.
 
                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (IN MILLIONS)
 
<TABLE>
<CAPTION>
                                                               YEAR ENDED DECEMBER 31,
                                                              --------------------------
                                                               1998     1997      1996
                                                              ------   -------   -------
<S>                                                           <C>      <C>       <C>
Cash flows from operating activities
  Net income (loss).........................................  $  225   $   130   $   (71)
  Adjustments to reconcile net income (loss) to net cash
    provided by operating activities
    Depreciation, depletion and amortization................     201       177       194
    Undistributed earning in equity investments.............     (27)       (3)       13
    Deferred income taxes (benefit).........................      95       192       (20)
    Gain on disposition of property.........................     (19)       (1)      (35)
    Extraordinary loss, net of tax..........................      --        --       234
    Cash paid for interest allocated to affiliates, net of
     tax....................................................      --        --      (139)
    Working capital changes, net of non-cash transactions
      Accounts and notes receivable.........................     758       576      (126)
      Inventories...........................................      20        14       (20)
      Other current assets..................................      29       (47)       22
      Net price risk management activities..................     (27)       16       (39)
      Regulatory assets.....................................     122        10        --
      Accounts payable......................................    (299)     (212)      240
      Accrual for regulatory issues.........................      13      (146)       32
      Other current liabilities.............................      (2)     (173)     (261)
    Decrease in long-term notes and other receivables
     (net)..................................................      --        --       455
    Other...................................................    (285)      (26)     (328)
                                                              ------   -------   -------
      Net cash provided by operating activities.............     804       507       151
                                                              ------   -------   -------
Cash flows from investing activities
  Capital expenditures......................................    (362)     (202)     (387)
  Investment in joint ventures and equity investees.........    (444)     (227)      (65)
  Net proceeds from disposal of property and investments....      60        58       465
  Net change in advances to EPEC............................    (223)      368      (198)
  Proceeds from equity investment project financing.........     153        --        --
  Net cash flow impact of acquisitions......................      --      (197)       --
  Investment in annuity.....................................      --       (40)       --
  Other.....................................................       2        --       (43)
                                                              ------   -------   -------
    Net cash used in investing activities...................    (814)     (240)     (228)
                                                              ------   -------   -------
Cash flows from financing activities
  Net commercial paper borrowings...........................     190        --        --
  Issuance of Old Tenneco common and treasury shares........      --        --       164
  Issuance of Series A Preferred Stock......................      --        --       296
  Issuance of Series B Preferred Stock......................      --       150        --
  Purchase of Old Tenneco common stock......................      --        --      (172)
  Redemption of Old Tenneco preferred stock.................      --        --       (20)
  Dividends paid (common and preferred stock)...............     (25)      (36)     (321)
  Increase (decrease) in borrowings under the Credit
    Facility................................................    (417)   (1,183)    1,600
  Increase (decrease) in note payable to affiliate..........     (90)      (45)      170
  Net decrease in other short-term debt excluding current
    maturities on long-term debt............................      --        --      (410)
  Long-term debt issuance, net..............................     391       883       310
  Long-term debt retirements................................     (46)      (15)   (2,270)
  Net cash contributions from affiliates....................      --        --       476
                                                              ------   -------   -------
    Net cash provided by (used in) financing activities.....       3      (246)     (177)
                                                              ------   -------   -------
Increase (decrease) in cash and temporary cash
  investments...............................................      (7)       21      (254)
Cash and temporary cash investments
  Beginning of period.......................................      35        14       268
                                                              ------   -------   -------
  End of period.............................................  $   28   $    35   $    14
                                                              ======   =======   =======
</TABLE>
 
              The accompanying Notes are an integral part of these
                       Consolidated Financial Statements.
 
                                       36
<PAGE>   41
 
                         EL PASO TENNESSEE PIPELINE CO.
 
           STATEMENTS OF CHANGES IN CONSOLIDATED STOCKHOLDERS' EQUITY
                      (IN MILLIONS, EXCEPT SHARE AMOUNTS)
 
<TABLE>
<CAPTION>
                                    COMMON STOCK     SERIES A    ADDITIONAL               ACCUMULATED
                                   ---------------   PREFERRED    PAID-IN     RETAINED   COMPREHENSIVE   COMBINED    TOTAL
                                   SHARES   AMOUNT     STOCK      CAPITAL     EARNINGS      INCOME        EQUITY    EQUITY
                                   ------   ------   ---------   ----------   --------   -------------   --------   -------
<S>                                <C>      <C>      <C>         <C>          <C>        <C>             <C>        <C>
January 1, 1996 Combined
  equity.........................    971    $  --      $ --        $  505       $  3         $ --        $   687    $ 1,195
  Net income (loss)..............                                                 34                        (105)       (71)
  Cash paid for interest
    allocated to affiliates, net
    of tax.......................                                                                           (139)      (139)
  Change in corporate debt
    allocated to affiliates......                                                                         (2,292)    (2,292)
  Cash distributions to
    affiliates, net..............                                                                            476        476
  Noncash contributions from
    affiliates, net..............                                                                          2,126      2,126
  Distributions to Old Tenneco
    stockholders, net............                                                                           (267)      (267)
  Issuance of Series A Preferred
    Stock........................                       296                                                             296
  Merger transaction.............  1,000                              486                                   (486)        --
  Acquisition adjustment to
    record assets and liabilities
    at fair value................                                     452                                               452
                                   -----    ------     ----        ------       ----         ----        -------    -------
December 31, 1996 Consolidated
  equity.........................  1,971       --       296         1,443         37           --             --      1,776
  Net income.....................                                                130                                    130
  Dividends......................                                                (36)                                   (36)
  Capital contribution...........                                      44                                                44
  Foreign currency translation
    adjustments..................                                                              (7)                       (7)
Other............................                         4             2                                                 6
                                   -----    ------     ----        ------       ----         ----        -------    -------
December 31, 1997 Consolidated
  equity.........................  1,971       --       300         1,489        131           (7)            --      1,913
  Net income.....................                                                225                                    225
  Dividends......................                                                (25)                                   (25)
  Capital contribution...........                                      47                                                47
  Foreign currency translation
    adjustments..................                                                              (7)                       (7)
  Other..........................                                       4         (4)                                    --
                                   -----    ------     ----        ------       ----         ----        -------    -------
December 31, 1998 Consolidated
  equity.........................  1,971    $  --      $300        $1,540       $327         $(14)       $    --    $ 2,153
                                   =====    ======     ====        ======       ====         ====        =======    =======
</TABLE>
 
              The accompanying Notes are an integral part of these
                       Consolidated Financial Statements.
                                       37
<PAGE>   42
 
                         EL PASO TENNESSEE PIPELINE CO.
 
                CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                                 (IN MILLIONS)
 
<TABLE>
<CAPTION>
                                                               YEAR ENDED DECEMBER 31,
                                                              -------------------------
                                                              1998      1997      1996
                                                              -----     -----     -----
<S>                                                           <C>       <C>       <C>
Net income (loss)...........................................  $225      $130      $(71)
Foreign currency translation adjustments....................    (7)       (7)       --
                                                              ----      ----      ----
Comprehensive income........................................  $218      $123      $(71)
                                                              ====      ====      ====
</TABLE>
 
                 The accompanying Notes are an integral part of
                    these Consolidated Financial Statements.
 
                                       38
<PAGE>   43
 
                         EL PASO TENNESSEE PIPELINE CO.
 
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICY
 
  Change in Company Structure
 
     On December 31, 1998, EPEC completed a series of steps to effect a tax-free
internal restructuring. In an initial step, certain energy marketing operations
were transferred to EPTPC from its former parent, EPNG, in exchange for 934,000
shares of Series C Preferred Stock, in a transaction valued at $47 million. On
December 31, 1998, the field services operations of EPFS and the international
operations of EPEI were transferred to EPTPC by its former parent and became
subsidiaries of EPTPC. EPTPC issued 971 shares of its common stock to EPNG as
consideration for (i) the assets and operations transferred to EPTPC, (ii) the
redemption of Series C Preferred Stock, and (iii) the redemption of Series B
Preferred Stock that had been issued in March 1997 for the forgiveness of
intercompany debt. This transaction had a total value of $667 million at
December 31, 1998. EPNG then distributed the common stock received in the
exchange to EPEC who, as a result, became the parent of the Company. The
restructuring transactions were treated as a transfer of ownership between
entities under common control and were accounted for in a manner similar to a
pooling of interests. Accordingly, all information in these financial statements
has been restated as though the transactions occurred in the earliest period
presented. As of January 1, 1996, the value assigned to EPTPC's common stock
issued in the reorganization was $508 million which represented the value of the
items exchanged as of that date.
 
     As part of the reorganization, EPTPC also transferred certain assets and
liabilities of corporate and discontinued operations to EPEC. EPTPC continues to
own the interstate systems known as the TGP system, the East Tennessee system,
and the Midwestern system, as well as certain discontinued operations not
included in the transfer to EPEC.
 
     The following table reflects the operating revenues and net income,
excluding the effects of the tax-free internal restructuring, for the periods
ended December 31:
 
<TABLE>
<CAPTION>
                                                                1998        1997        1996
                                                              --------    --------    --------
                                                                       (IN MILLIONS)
<S>                                                           <C>         <C>         <C>
Operating revenues..........................................   $5,059      $3,602      $2,208
Net income (loss)...........................................      209         112        (105)
</TABLE>
 
  Basis of Presentation and Principles of Consolidation
 
     The consolidated financial statements include the accounts of all
majority-owned, controlled subsidiaries of the Company after the elimination of
all significant intercompany accounts and transactions. Investments in companies
where the Company has the ability to exert significant influence over, but not
control operating and financial policies are accounted for using the equity
method. The financial statements for previous periods include certain
reclassifications that were made to conform to the current year presentation.
Such reclassifications have no impact on reported net income or stockholders'
equity. In 1996, Old Tenneco reorganized its businesses along an operational
basis. As a result, Old Tenneco's operations consisted solely of its energy
related businesses and certain discontinued operations. Financial information
for periods prior to the acquisition of Old Tenneco in December 1996 by EPEC,
has been prepared on a combined basis.
 
  Use of Estimates
 
     The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses and disclosure of contingent assets and liabilities that exist at
the date of the financial statements. Actual results are likely to differ from
those estimates.
 
                                       39
<PAGE>   44
 
  Accounting for Regulated Operations
 
     The Company's businesses that are subject to the regulations and accounting
requirements of FERC have followed the accounting requirements of SFAS No. 71,
Accounting for the Effects of Certain Types of Regulation, which may differ from
the accounting requirements of the Company's non-regulated entities.
Transactions that have been recorded differently as a result of regulatory
accounting requirements include: GSR costs to be recovered under a demand and
interruptible surcharge, environmental costs to be recovered under a demand
surcharge, and certain benefits and other costs and taxes included in or
expected to be included in future rates, including costs to refinance debt. When
the accounting method followed is prescribed by or allowed by the regulatory
authority for rate-making purposes, such method conforms to the generally
accepted accounting principle of matching costs with the revenues to which they
apply.
 
  Cash and Temporary Investments
 
     Short-term investments purchased with an original maturity of three months
or less are considered cash equivalents.
 
  Allowance for Doubtful Accounts and Notes Receivable
 
     The Company has established a provision for losses on accounts and notes
receivable, as well as for gas imbalances due from shippers and operators, which
may become uncollectible. Collectibility is reviewed regularly, and the
allowance is adjusted as necessary primarily under the specific identification
method. The balances of this provision at December 31, 1998 and 1997, were $26
million and $39 million, respectively.
 
  Gas Imbalances
 
     The Company values gas imbalances due to or due from shippers and operators
at the appropriate index price. Natural gas imbalances are settled in cash or
made up in-kind.
 
  Inventories
 
     Inventories, consisting of materials and supplies and natural gas in
storage, are valued at the lower of cost or market with cost determined using
the average cost method.
 
  Property, Plant, and Equipment
 
     Included in the Company's property, plant, and equipment is construction
work in progress of approximately $363 million and $210 million at December 31,
1998, and 1997, respectively. An allowance for both debt and equity funds used
during construction of regulated projects is included in the cost of the
Company's property, plant, and equipment.
 
     Accounting for a substantial portion of property, plant, and equipment is
subject to regulation by the FERC. The objectives of this regulation are to
ensure the proper recovery of capital investments in rates. Such recovery is
generally accomplished by allowing a return of the investment through inclusion
of depreciation expense in the cost of service. Rates also allow for a return on
the net unrecovered rate base. Specific procedures are prescribed by FERC to
control capitalized costs, depreciation, and the disposal of assets. SFAS No. 71
specifically acknowledges the obligation of regulated companies to comply with
regulated accounting procedures, even when they conflict with other generally
accepted accounting principle pronouncements.
 
     Regulated property, plant, and equipment is recorded at original cost of
construction or, on acquisition, the cost of first party committing the asset to
utility services. Construction cost includes direct labor and materials, as well
as indirect charges such as overheads and allowance for funds used during
construction. Replacements or betterments of major units of property are
capitalized. Replacements or additions of minor units of property are expensed.
 
     Depreciation for regulated property, plant, and equipment is calculated
using the composite method. Assets with similar economic characteristics are
grouped. The depreciation rate prescribed in the rate
 
                                       40
<PAGE>   45
 
settlement is applied to the gross investment for the group until net book value
of the group is equal to the salvage value. Currently, depreciation rates vary
from 1 percent to 24 percent. This results in remaining economic lives of groups
ranging from 2 to 30 years. Depreciation rates are reevaluated in conjunction
with the rate making process.
 
     When regulated property, plant, and equipment is retired, due to
abandonment or replacement, the original cost, plus the cost of retirement, less
salvage, is charged to accumulated depreciation and amortization. No gain or
loss is recognized unless an entire operating unit, as defined by FERC, has been
retired. Gains or losses on dispositions of operating units are included in
income.
 
     Additional acquisition cost assigned to utility plant primarily represents
the excess of allocated purchase costs over historical costs that resulted from
the December 1996 acquisition of EPTPC. These costs are being amortized on a
straight-line basis using FERC approved rates.
 
     Depreciation of the Company's non-regulated properties is provided using
the straight line or composite method which, in the opinion of management, is
adequate to allocate the cost of properties over their estimated useful lives.
Non-regulated properties have expected lives of 5 to 40 years.
 
     The Company evaluates impairment of its property, plant, and equipment in
accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed Of.
 
  Intangible Assets
 
     Intangible assets are amortized using the straight-line method over periods
ranging from 5 years to 40 years. Accumulated amortization of intangible assets
was $13 million and $9 million for 1998 and 1997, respectively.
 
     The Company evaluates impairment of goodwill in accordance with SFAS No.
121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of.
 
  Environmental Costs
 
     Expenditures for ongoing compliance with environmental regulations that
relate to current operations are expensed or capitalized as appropriate.
Expenditures that relate to an existing condition caused by past operations, and
which do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments indicate that
remediation efforts are probable and the costs can be reasonably estimated.
Estimates of the liability are based upon currently available facts, existing
technology and presently enacted laws and regulations taking into consideration
the likely effects of inflation and other societal and economic factors, and
include estimates of associated legal costs. All available evidence is
considered including prior experience in remediation of contaminated sites,
other companies' clean-up experience and data released by the EPA or other
organizations. These estimated liabilities are subject to revision in future
periods based on actual costs or new circumstances. These liabilities are
included in the balance sheets at their undiscounted amounts. Recoveries are
evaluated separately from the liability and, when recovery is assured, are
recorded and reported separately from the associated liability in the
consolidated financial statements as an asset.
 
  Price Risk Management Activities
 
     The Company utilizes derivative financial instruments to manage market
risks associated with certain energy commodities, and interest rates. In its
commodity price risk management activities, the Company engages in both trading
and non-trading activities.
 
     Activities for trading purposes consist of services provided to the energy
sector, and all energy trading activities, including transportation capacity and
storage, are accounted for using the mark-to-market method of accounting. Such
trading activities are conducted through a variety of financial instruments,
including forward contracts involving cash settlement or physical delivery of an
energy commodity, swap contracts which require payments to (or receipts from)
counterparties based on the differential between a fixed and
 
                                       41
<PAGE>   46
 
variable price for the commodity, exchange-trade options, over-the-counter
options, and other contractual arrangements.
 
     Under mark-to-market accounting, commodity and energy related contracts are
reflected at estimated market value with resulting gains and losses recorded in
operating income in the Consolidated Statements of Income. The net gains or
losses recognized in the current period result primarily from transactions
originating within the period and the impact of price movements on transactions
originating in previous periods. The assets and liabilities resulting from
mark-to-market accounting are presented as assets and liabilities from price
risk management activities in the Consolidated Balance Sheets. 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 in accounts receivable and accounts payable in the
Consolidated Balance Sheets. Cash inflows and outflows associated with these
price risk management activities are recognized in operating cash flow as the
settlements of transactions occur.
 
     The market value of these commodity and energy related contracts reflects
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 the Company's position in an orderly manner over a
reasonable period of time under present market conditions.
 
     Derivative and other financial instruments are also utilized in connection
with non-trading activities. The Company enters into forwards, swaps, and other
contracts to hedge the impact of market fluctuations on assets, liabilities, or
other contractual commitments. Derivatives held for non-trading price risk
management activities are not recorded on the balance sheet. Net periodic
settlements are recorded as a gain or loss in operating income in the
consolidated statements of income, and cash inflows and outflows are recognized
in operating cash flow as the settlements of the transactions occur. See Note 4
for a further discussion of the Company's price risk management activities.
 
     In late 1998, the Emerging Issues Task Force reached a consensus which
supported the Company's accounting policy as described above.
 
  Income Taxes
 
     Income taxes are based on income reported for tax return purposes along
with a provision for deferred income taxes. Deferred income taxes are provided
to reflect the tax consequences in future years of differences between the
financial statement and tax bases of assets and liabilities at each year end.
Tax credits are accounted for under the flow-through method, which reduces the
provision for income taxes in the year the tax credits first become available.
Deferred tax assets are reduced by a valuation allowance when, based upon
management's estimates, it is more likely than not that a portion of the
deferred tax assets will not be realized in a future period. The estimates
utilized in the recognition of deferred tax assets are subject to revision in
future periods based on new facts or circumstances.
 
     Old Tenneco, together with certain of its subsidiaries which were owned 80
percent or more, including subsidiaries in its industrial business and the
shipbuilding business, had an agreement to file a consolidated U.S. federal
income tax return. Such agreement provided, among other things, that (i) each
company in a taxable income position would be charged with an amount equivalent
to its federal income tax computed on a separate return basis, and (ii) each
company in a tax loss position would be reimbursed to the extent that its
deductions, including general business credits, were utilized in the
consolidated return. Management believes that income tax amounts reflected in
the financial statements of the Company prior to the acquisition by EPEC under
the provisions of the tax sharing arrangement would not be materially different
from the income taxes which would have been provided had the Company filed a
separate consolidated tax return. Under the tax sharing agreement, Old Tenneco
paid all federal taxes directly and billed or refunded, as applicable, its
subsidiaries for the applicable portion of the total tax payments. This tax
sharing agreement remains in effect for 1998 among EPTPC and certain of its
subsidiaries which are owned 80 percent or more. Starting in 1999, EPEC and its
80 percent or more owned subsidiaries, including EPTPC, will file a consolidated
U.S. federal income tax return.
 
                                       42
<PAGE>   47
 
     On behalf of itself and all members filing in its consolidated federal
income tax return, EPNG adopted a tax sharing policy (the "Policy") which
provides, among other things, that (i) each company in a taxable income position
will be currently charged with an amount equivalent to its federal income tax
computed on a separate return basis, and (ii) each company in a tax loss
position will be reimbursed currently to the extent its deductions, including
general business credits, were utilized in the consolidated return. Under the
Policy, EPNG paid all federal income taxes through 1998 directly to the IRS and
will bill or refund, as applicable, its subsidiaries for their applicable
portion of such income tax payments. The subsidiaries that were transferred to
EPTPC as part of the tax-free internal reorganization will be included in the
1998 EPEC consolidated federal income tax return. These subsidiaries will
continue to be included in the EPNG tax sharing policy through 1998.
 
     As a result of the acquisition by EPEC, the Company entered into a new tax
sharing agreement with Newport News Shipbuilding, Inc., New Tenneco and EPNG.
This new tax sharing agreement provides, among other things, for the allocation
among the parties of tax assets and liabilities arising prior to, as a result
of, and subsequent to the distributions. Generally, EPTPC will be liable for
taxes imposed on itself. With respect to periods prior to the consummation of
the distributions, in the case of federal income taxes imposed on the combined
activities of Old Tenneco and other members of its consolidated group prior to
the distributions, New Tenneco and Newport News Shipbuilding, Inc. are liable to
the Company for federal income taxes attributable to their activities, and each
will be allocated an agreed-upon share of estimated tax payments made by EPTPC
for Old Tenneco. Pursuant to the new tax sharing agreement, the Company paid New
Tenneco in 1997 for the tax benefits realized from the deduction of 1996 taxable
losses generated by a debt realignment effected in accordance with the merger
agreement.
 
  New Accounting Pronouncements Not Yet Adopted
 
     See Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations, New Accounting Pronouncements Not Yet Adopted, which is
incorporated herein by reference.
 
2. ACQUISITION BY EPEC
 
     In December 1996, EPEC acquired all of the common stock of EPTPC. As of
December 31, 1998, EPEC owns 100 percent of the common stock of EPTPC,
representing over 80 percent of the equity value of EPTPC; and the balance of
the equity value of EPTPC is held by the holders of its Series A Preferred
Stock.
 
     In preparation for the acquisition by EPEC, Old Tenneco initiated tender
offers for certain issues of the Company's debt and certain other debt issues
were exchanged into New Tenneco debt, defeased or otherwise retired. Upon
completion of the debt realignment transactions, the Company was only
responsible for the remaining debt which was not tendered, exchanged, defeased
or otherwise retired. The Company recognized an after-tax extraordinary charge
of $234 million in 1996 (net of $126 million income tax benefit) related to the
debt realignment immediately prior to the acquisition by EPEC.
 
     The consideration provided in the acquisition by EPEC was approximately $4
billion, including retained debt and EPEC equity consideration valued at $913
million.
 
  Accounting for Acquisition by EPEC
 
     The acquisition of the Company by EPEC was accounted for using the purchase
method of accounting. Accordingly, an allocation of the purchase price was
assigned to the assets and liabilities acquired based upon the estimated fair
value of those assets and liabilities as of the acquisition date. Substantially
all of the excess of the purchase price over historical carrying amounts of net
assets acquired was allocated to the property, plant and equipment of the
Company's interstate pipeline systems. Such allocation was confirmed by an
independent appraisal of the property acquired. Current FERC policy does not
permit the Company to recover through its rates amounts allocated in purchase
accounting to its regulated operations in excess of original cost.
 
     The Consolidated Balance Sheets of EPTPC and subsidiaries as of December
31, 1998 and 1997, contained herein reflect the purchase price recorded by EPEC.
                                       43
<PAGE>   48
 
3. FINANCING TRANSACTIONS
 
     The average interest rate of short-term borrowings was 6.0% and 5.8% at
December 31, 1998, and 1997, respectively. The Company had short-term
borrowings, including current maturities of long-term debt, at December 31, 1998
and December 31, 1997, as follows:
 
<TABLE>
<CAPTION>
                                                               1998       1997
                                                              ------     ------
                                                                (IN MILLIONS)
<S>                                                           <C>        <C>
EPNG Revolving Credit Facility with TGP designated as
  borrower..................................................  $   --     $  417
Commercial paper............................................     190         --
Current maturities of other long-term debt..................       4         46
                                                              ------     ------
                                                              $  194     $  463
                                                              ======     ======
</TABLE>
 
     Long-term debt outstanding at December 31, 1998 and 1997, consisted of the
following:
 
<TABLE>
<CAPTION>
                                                               1998       1997
                                                              ------     ------
                                                                (IN MILLIONS)
<S>                                                           <C>        <C>
Long-term debt
  EPTPC
     Debentures due 2008 through 2025, average effective
      interest rate of 7.3% in 1998 and 7.2% in 1997, net of
      unamortized premium of $3.5 in 1998 ($4.0 in 1997)....  $   54     $   55
     Notes due 1998 through 2005, average effective interest
      rate of 6.5% in 1998 and 6.4% in 1997, net of
      unamortized premium of $2.3 in 1998 ($4.1 in 1997)....      48         87
  TGP
     Debentures due 2011, average effective interest rate of
      7.5% in 1998 and 7.9% in 1997, net of unamortized
      discount of $10.6 in 1998 ($11.1 in 1997).............      75         75
     Debentures due 2017, average effective interest rate of
      7.7% in 1998 and 7.8% in 1997, net of unamortized
      discount of $4.7 in 1998 ($5.0 in 1997)...............     295        295
     Debentures due 2027, average effective interest rate of
      7.1% in 1998 and 7.2% in 1997, net of unamortized
      discount of $3.6 in 1998 ($3.7 in 1997)...............     296        296
     Debentures due 2028, average effective interest rate of
      7.2% in 1998, net of unamortized discount of $8.9 in
      1998..................................................     391         --
     Debentures due 2037, average effective interest rate of
      7.8% in 1998 and 7.9% in 1997, net of unamortized
      discount of $6.3 in 1998 ($6.5 in 1997)...............     294        293
  EPEC Corporation, successor to El Paso Energy Credit
     Corporation
     Senior note due 2001, average effective interest rate
      of 6.6% in 1998 and 6.0% in 1997, net of unamortized
      premium of $0.9 in 1998
       ($1.2 in 1997).......................................      14         15
     Subordinated notes due 1998, average effective interest
      rate of 6.5% in 1997, net of unamortized premium of
      $0.2 in 1997..........................................      --          7
  Other
     Notes due 1998 through 2014, average effective interest
      rate of 9.8% in 1998 and 8.7% in 1997.................       4          5
                                                              ------     ------
                                                               1,471      1,128
  Less current maturities...................................       4         46
                                                              ------     ------
          Total long-term debt..............................  $1,467     $1,082
                                                              ======     ======
</TABLE>
 
                                       44
<PAGE>   49
 
     The following are aggregate maturities of long-term debt for the next 5
years and in total thereafter:
 
<TABLE>
<CAPTION>
                                                              (IN MILLIONS)
                                                              -------------
<S>                                                           <C>
1999........................................................     $    4
2000........................................................          9
2001........................................................         40
2002........................................................         12
2003........................................................         --
Thereafter..................................................      1,406
                                                                 ------
          Total long-term debt, including current
           maturities.......................................     $1,471
                                                                 ======
</TABLE>
 
  Other Financing Arrangements
 
     In March 1997, TGP issued $300 million aggregate principal amount of 7 1/2%
debentures due 2017, $300 million aggregate principal amount of 7% debentures
due 2027, and $300 million aggregate principal amount of 7 5/8% debentures due
2037. Proceeds of approximately $883 million, net of issuance costs, were used
to repay a portion of EPTPC's credit facility and for general corporate
purposes.
 
     In October 1997, EPNG established a new $750 million five-year revolving
credit and competitive advance facility and a new $750 million 364-day renewable
revolving credit and competitive advance facility (collectively, the "Revolving
Credit Facility"). In connection with the establishment of the Revolving Credit
Facility, EPTPC's revolving credit facility was also terminated, and the
outstanding balance of $417 million was financed under the five-year portion of
the new Revolving Credit Facility with TGP designated as the borrower. The
availability under the Revolving Credit Facility is expected to be used for
general corporate purposes including, but not limited to, backstopping EPNG's
and TGP's $1 billion commercial paper programs.
 
     In August 1998, EPEC became a guarantor of the Revolving Credit Facility.
In October 1998, the $750 million 364-day portion of the Revolving Credit
Facility was amended to extend the termination date to October 27, 1999. In
addition, in October 1998, the Revolving Credit Facility was amended to permit
TGP to issue commercial paper, provided that the total amount of commercial
paper outstanding at EPNG and TGP is equal to or less than the unused capacity
under the Revolving Credit Facility. In December 1998, EPEC became a borrower
under the Revolving Credit Facility. The interest rate is 40 basis points above
LIBOR, with the spread varying based on EPEC's long-term debt credit rating.
 
     The availability of borrowings under the Revolving Credit Facility is
subject to specified conditions, which management believes the Company currently
meets. 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 since the
specified dates).
 
     In September 1998, TGP filed a shelf registration permitting TGP to offer
up to $600 million (including $100 million carried forward from a prior shelf
registration) of debt securities. In October 1998, TGP issued $400 million
aggregate principal amount of 7% debentures due 2028. Proceeds to TGP were
approximately $391 million, net of issuance cost. Approximately $300 million of
the proceeds were used to repay TGP's short-term indebtedness under the
Revolving Credit Facility and the remainder were used by TGP for general
corporate purposes. After this issuance, TGP has $200 million of capacity
remaining under its existing shelf registration.
 
     In August 1998, EPTPC retired its outstanding 10% debentures due August 1,
1998, in the amount of $38 million.
 
                                       45
<PAGE>   50
 
4. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES
 
  Fair Value of Financial Instruments
 
     The following disclosure of the estimated fair value of financial
instruments is presented in accordance with the requirements of SFAS No. 107.
The estimated fair value amounts have been determined by the Company using
available market information and valuation methodologies.
 
     As of December 31, 1998, and 1997, the carrying amounts of certain
financial instruments held by the Company, including cash, cash equivalents,
short-term borrowings and investments, and trade receivables and payables are
representative of fair value because of the short-term maturity of these
instruments. The fair value of long-term debt with variable interest rates is
the carrying value because of the variable nature of the respective debt's
interest rate, and the fair value of debt with fixed interest rates has been
estimated based on quoted market prices for the same or similar issues. The fair
value of all derivative financial instruments is the estimated amount at which
management believes the instruments could be liquidated over a reasonable period
of time, based on quoted market prices, current market conditions, or other
estimates obtained from third-party brokers or dealers.
 
     The following table reflects the carrying amount and estimated fair value
of the Company's financial instruments at December 31:
 
<TABLE>
<CAPTION>
                                                               1998                     1997
                                                       ---------------------    ---------------------
                                                       CARRYING                 CARRYING
                                                        AMOUNT    FAIR VALUE     AMOUNT    FAIR VALUE
                                                       --------   ----------    --------   ----------
                                                                       (IN MILLIONS)
<S>                                                    <C>        <C>           <C>        <C>
Balance sheet financial instruments:
  Long-term debt.....................................   $1,471      $1,563       $1,128      $1,199
Other financial instruments:
  Trading
     Futures contracts...............................       (3)         (3)          (3)         (3)
     Option contracts................................       75          75            3           3
     Swap and forward contracts......................      (40)        (40)          23          23
  Non-Trading
     Equity swap.....................................        3           3            6           8
     Commodity option contracts......................       --           1           --           1
     Commodity swap and forwards contracts...........       --         (14)          --           4
</TABLE>
 
  Trading Commodity Activities
 
     The Company, through its merchant services business, offers integrated
price risk management services to the energy sector. These services primarily
relate to energy related commodities including natural gas, power and petroleum
products. The Company provides these services through a variety of contracts
entered into for trading purposes including forward contracts involving cash
settlements or physical delivery of an energy commodity, swap contracts, which
require payments to (or receipt of payments from) counterparties based on the
differential between a fixed and variable price for the commodity, options and
other contractual arrangements. Effective December 31, 1998, the operations
related to power trading were transferred to El Paso Power Services, a
subsidiary of EPEC.
 
                                       46
<PAGE>   51
 
     The fair value of commodity and energy related contracts entered into for
trading purposes as of December 31, 1998, and 1997, and the average fair value
of those instruments held during the years ended December 31, 1998, and 1997 are
set forth below. At December 31, 1998, $76 million of assets from price risk
management activities are included in other assets and $33 million of
liabilities from price risk management activities are included in other
liabilities in the Consolidated Balance Sheets.
 
<TABLE>
<CAPTION>
                                                                                AVERAGE FAIR
                                                                                VALUE FOR THE
                                                       ASSETS    LIABILITIES       YEAR(A)
                                                       ------    -----------    -------------
                                                                   (IN MILLIONS)
<S>                                                    <C>       <C>            <C>
1998
Futures contracts....................................   $  2        $  (4)          $ (4)
Option contracts.....................................    142           (8)            30
Swap and forward contracts...........................     83         (123)           (39)
1997
Futures contracts....................................   $  4        $  (7)          $ --
Option contracts.....................................     15          (12)             2
Swap and forward contracts...........................     77          (54)            13
</TABLE>
 
---------------
 
(a) Computed using the net asset balance at each month end.
 
  Notional Amounts and Terms
 
     The notional amounts and terms of these financial instruments at December
31, 1998, and 1997 are set forth below (natural gas volumes in trillions of
British thermal units, power volumes in millions of megawatt hours, petroleum
products volumes in millions of British thermal units equivalent):
 
<TABLE>
<CAPTION>
                                                 FIXED PRICE    FIXED PRICE       MAXIMUM
                                                    PAYOR        RECEIVER      TERMS IN YEARS
                                                 -----------    -----------    --------------
<S>                                              <C>            <C>            <C>
1998
Energy Commodities:
  Natural gas..................................     9,605          8,866             20
  Petroleum products...........................        67             72              2
1997
Energy Commodities:
  Natural gas..................................     4,079          3,584             20
  Power........................................        12             13              1
  Petroleum products...........................       197            195              2
</TABLE>
 
     Notional amounts reflect the volume of transactions but do not represent
the amounts exchanged by the parties. Accordingly, notional amounts are an
incomplete measure of the Company's exposure to market or credit risks. The
maximum terms in years detailed above are not indicative of likely future cash
flows as these positions may be offset or cashed-out in the markets at any time
based on the Company's risk management needs and liquidity in the commodity
markets.
 
     The weighted average maturity of the Company's entire portfolio of price
risk management activities was approximately two years as of December 31, 1998
and 1997, respectively.
 
  Market and Credit Risks
 
     The Company serves a diverse customer group that includes independent power
producers, industrial companies, gas and electric utilities, oil and gas
producers, financial institutions and other energy marketers. This broad
customer mix generates a need for a variety of financial structures, products
and terms. This diversity requires the Company to manage, on a portfolio basis,
the resulting market risks inherent in these transactions subject to parameters
established by the Company's risk management committee. Market risks are
monitored by a risk control committee operating independently from the units
that create or actively manage these risk exposures to ensure compliance with
the Company's stated risk management policies.
 
                                       47
<PAGE>   52
 
     The Company measures and adjusts the risk in its portfolio in accordance
with mark-to-market and other risk management methodologies which utilize
forward price curves in the energy markets to estimate the size and probability
of future potential exposure.
 
     Credit risk relates to the risk of loss that the Company would incur as a
result of non-performance by counterparties pursuant to the terms of their
contractual obligations. The Company maintains credit policies with regard to
its counterparties to minimize overall credit risk. These policies require an
evaluation of potential counterparties' financial condition (including credit
rating), collateral requirements under certain circumstances (including cash in
advance, letters of credit, and parental guarantees), and the use of
standardized agreements which allow for the netting of positive and negative
exposures associated with a single counterparty. The counterparties associated
with the Company's assets from price risk management activities as of December
31, 1998, and 1997 are summarized as follows:
 
<TABLE>
<CAPTION>
                                               ASSETS FROM PRICE RISK MANAGEMENT ACTIVITIES
                                                          AS OF DECEMBER 31, 1998
                                            ---------------------------------------------------
                                                                        BELOW
                                            INVESTMENT GRADE(A)    INVESTMENT GRADE    TOTAL(B)
                                            -------------------    ----------------    --------
                                                               (IN MILLIONS)
<S>                                         <C>                    <C>                 <C>
Energy marketers..........................         $ 48                  $ 4             $ 52
Financial institutions....................           21                   --               21
Oil and gas producers.....................           33                    5               38
Gas and electric utilities................           86                    6               92
Industrials...............................           18                   --               18
Other.....................................            4                    2                6
                                                   ----                  ---             ----
          Total assets from price risk
            management activities.........         $210                  $17             $227
                                                   ====                  ===             ====
</TABLE>
 
<TABLE>
<CAPTION>
                                               ASSETS FROM PRICE RISK MANAGEMENT ACTIVITIES
                                                          AS OF DECEMBER 31, 1997
                                            ---------------------------------------------------
                                                                        BELOW
                                            INVESTMENT GRADE(A)    INVESTMENT GRADE     TOTAL
                                            -------------------    ----------------    --------
                                                               (IN MILLIONS)
<S>                                         <C>                    <C>                 <C>
Energy marketers..........................          $21                  $ 3             $24
Financial institutions....................           20                   --              20
Oil and gas producers.....................           14                    4              18
Gas and electric utilities................           16                    2              18
Industrials...............................            6                    1               7
Other.....................................            8                    1               9
                                                    ---                  ---             ---
          Total assets from price risk
            management activities.........          $85                  $11             $96
                                                    ===                  ===             ===
</TABLE>
 
---------------
 
(a)  "Investment Grade" is primarily determined using publicly available credit
     ratings along with consideration of collateral, which encompass standby
     letters of credit, parent company guarantees and property interest,
     including oil and gas reserves. Included in Investment Grade are
     counterparties with a minimum Standard & Poor's or Moody's rating of BBB-
     or Baa3, respectively, or minimum implied (through internal credit
     analysis) Standard & Poor's equivalent rating of BBB-.
 
(b)  Two customers' exposure at December 31, 1998, and 1997 comprise greater
     than 5 percent of assets from price risk management activities. These
     customers have Investment Grade ratings.
 
     This concentration of counterparties may impact the Company's overall
exposure to credit risk, either positively or negatively, in that the
counterparties may be similarly affected by changes in economic, regulatory or
other conditions. Based on the Company's policies, risk exposure, and reserves,
the Company does not anticipate a material adverse effect on its financial
position, or results of operations, or cash flows as a result of counterparty
nonperformance.
 
                                       48
<PAGE>   53
 
  Non-Trading Price Risk Management Activities
 
     In March 1997, the Company purchased a 10.5 percent interest in CAPSA, a
privately held Argentine company engaged in power generation and oil and gas
production for approximately $57 million. In connection with this acquisition,
the Company entered into an equity swap transaction associated with an
additional 18.5 percent of CAPSA's then outstanding stock. Under the swap, the
Company pays interest to the counterparty, on a quarterly basis, on a notional
amount of $100 million at a rate of LIBOR plus 0.85 percent. In exchange, the
Company receives dividends on the CAPSA stock to the extent of the
counterparty's equity interest of 18.5 percent. The Company also fully
participates in the market appreciation or depreciation of the underlying
investment whereby the Company will realize appreciation or fund any
depreciation attributable to the actual sale of the stock upon termination or
expiration of the swap transaction. The initial term of the swap was two years,
and in February 1999, was extended for an additional two and one-half years.
Upon maturity or termination of the swap, the Company has a right of first
refusal to purchase the counterparty's 18.5 percent investment in CAPSA common
stock at the fair value of the stock at that date or at a later date at a price
offered by a good faith buyer. This transaction is recorded using mark-to-market
accounting.
 
5. COMMITMENTS AND CONTINGENCIES
 
     See Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations, Commitments and Contingencies and Environmental, which
are incorporated herein by reference.
 
6. INCOME TAXES
 
     The following table reflects the components of income tax expense for the
years ended December 31:
 
<TABLE>
<CAPTION>
                                                           1998           1997      1996
                                                           ----           ----      ----
                                                                (IN MILLIONS)
<S>                                                  <C>                  <C>       <C>
Current
  Federal .........................................        $ 11           $(84)     $ 20
  State and local..................................         (17)           (35)       42
  Foreign..........................................           5             --         1
                                                           ----           ----      ----
                                                             (1)          (119)       63
                                                           ----           ----      ----
Deferred
  Federal .........................................          88            156         1
  State and local..................................           9             36       (21)
  Foreign..........................................          (2)            --        --
                                                           ----           ----      ----
                                                             95            192       (20)
                                                           ----           ----      ----
       Total tax expense...........................        $ 94           $ 73      $ 43
                                                           ====           ====      ====
</TABLE>
 
                                       49
<PAGE>   54
 
     Tax expense of the Company 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>
                                                            1998           1997      1996
                                                            ----           ----      ----
                                                                 (IN MILLIONS)
<S>                                                   <C>                  <C>       <C>
Tax expense computed at the statutory U.S. federal
  income tax rate...................................        $112           $71       $ 72
Increases (reductions) in income tax expense
  resulting from:
  State and local taxes on income, net of U.S.
     federal income tax benefit.....................          (5)           --         14
  Permanent differences on sales of assets..........          (4)           --          8
  Realization of unrecognized deferred tax assets...          --            --        (38)
  Net reversal of tax reserves......................          --            --         (4)
  Undistributed earnings of foreign affiliates......          (8)           (3)        --
  Other.............................................          (1)            5         (9)
                                                            ----           ---       ----
Income tax expense (benefit)........................        $ 94           $73       $ 43
                                                            ====           ===       ====
Effective tax rate..................................          29%           36%        21%
                                                            ====           ===       ====
</TABLE>
 
     The following table reflects the components of the net deferred tax
liability at December 31:
 
<TABLE>
<CAPTION>
                                                               1998        1997
                                                              ------      ------
                                                                (IN MILLIONS)
<S>                                                           <C>         <C>
Deferred tax assets
  U.S. net operating loss and tax credit carryovers.........  $   60      $  113
  Postretirement benefits other than pensions...............     109          69
  Accrual for regulatory issues.............................     113         123
  Environmental reserve.....................................      62          95
  Other.....................................................     253         222
  Valuation allowance.......................................      (5)         (8)
                                                              ------      ------
  Total deferred tax asset..................................     592         614
                                                              ------      ------
Deferred tax liabilities
  Tax over book depreciation................................   1,632       1,604
  Regulatory issues.........................................      74          70
  Other.....................................................      87         201
                                                              ------      ------
  Total deferred tax liability..............................   1,793       1,875
                                                              ------      ------
Net deferred tax liability(a)...............................  $1,201      $1,261
                                                              ======      ======
</TABLE>
 
---------------
 
(a) As of December 31, 1998, $1 million of non-current foreign deferred income
    taxes are included in other assets and as of December 31, 1997, $4 million
    of current deferred state income taxes are included in other current
    liabilities in the Consolidated Balance Sheets.
 
     The cumulative undistributed earnings of certain foreign subsidiaries and
foreign corporate joint ventures were approximately $35 million as of December
31, 1998. Since the earnings have been or are intended to be indefinitely
reinvested in foreign operations, no provision has been made for any U.S. taxes
or foreign withholding taxes that may be applicable upon actual or deemed
repatriation. If a distribution of such earnings were to be made, the Company
may be subject to both foreign withholding taxes and U.S. income taxes, net of
any allowable foreign tax credits or deductions. However, an estimate of such
taxes is not practicable. For the same reasons, the Company has not provided for
any U.S. taxes on the foreign currency translation adjustments recognized in
comprehensive income.
 
                                       50
<PAGE>   55
 
     As of December 31, 1998, approximately $20 million of alternative minimum
tax credits were available to offset future regular tax liabilities. These
alternative minimum tax credit carryovers have no expiration date. Additionally,
at December 31, 1998, approximately $1 million of general business credit, $102
million of net operating loss, and $9 million of capital loss carryovers were
available to offset future tax liabilities. The general business credit
carryovers expire in the years 1999 and 2000. Approximately $57 million of the
net operating loss carryovers expire in 2012 and the remaining $45 million
expire in the years 2004 through 2011. Usage of these carryovers is subject to
the limitations provided for under Sections 382 and 383 of the Internal Revenue
Code as well as the separate return limitation year rules of the Treasury
Regulations.
 
     The Company has recorded a valuation allowance to reflect the estimated
amount of deferred tax assets which may not be realized due to the expiration of
net operating loss and tax credit carryovers. As of December 31, 1998, and 1997,
approximately $5 million and $8 million, respectively, of the valuation
allowance relates to the net operating loss carryovers of an acquired company.
The remainder of the valuation allowance relates to the general business credit
carryovers of an acquired company. Any tax benefits subsequently recognized from
reversal of this valuation allowance will be allocated to goodwill.
 
     Prior to 1999, EPTPC and its subsidiaries filed a consolidated federal
income tax return and EPEC and its other subsidiaries filed a separate
consolidated federal income tax return. As a result of the tax-free
reorganization described in Note 1, starting in 1999, EPEC and its subsidiaries,
including EPTPC and its subsidiaries, will file one consolidated federal income
tax return.
 
7. RETIREMENT BENEFITS
 
  Pension Benefits
 
     Prior to January 1, 1997 substantially all of the Company's employees were
covered under one of two defined benefit pension plans. Certain employees were
included in the Old Tenneco Retirement Plan ("TRP"). The related benefit
obligation is the responsibility of New Tenneco and as such, is not included in
the Consolidated Balance Sheets. The remaining employees were covered by the
EPEC defined benefit plan.
 
     Effective January 1, 1997, the EPEC plan was amended to provide benefits
determined by a cash balance formula and to include employees added as a result
of the acquisition of the Company by EPEC and other acquisitions prior to 1997.
Employees who were participants on December 31, 1996, received the greater of
cash balance benefits or prior plan benefits accrued through December 31, 2001.
 
     EPEC is responsible for benefits accrued under its defined benefit plan and
its cash balance plan and allocates the related costs to its affiliates.
 
     During 1997, EPEC offered special termination benefits to Company
employees, as a result of the acquisition of the Company by EPEC, who were at
least 55 years old and who were eligible to retire under the TRP on December 31,
1996. Eligible employees accepting this offer and retiring by July 1, 1997,
received a cash balance credit based on an enhanced formula not to exceed one
year's base salary. The cost associated with the special termination benefits
was accrued at December 31, 1996, as part of the liabilities assumed in the
acquisition by EPEC. In 1997, the Company funded $11 million for these special
termination benefits.
 
  Other Postretirement Benefits
 
     As a result of the acquisition by EPEC, EPTPC retained responsibility for
certain postretirement medical and life insurance benefits for former employees
of operations previously disposed of by Old Tenneco, and for employees,
including TGP employees, added as a result of the acquisition by EPEC who were
eligible to retire on December 31, 1996, and did so on or before July 1, 1997.
Medical benefits for this closed group of retirees may be subject to
deductibles, co-payment provisions, and other limitations and dollar caps on the
amount of employer costs. EPTPC has reserved the right to change these benefits.
Employees who retired on or after July 1, 1997 will continue to receive limited
postretirement life insurance benefits. TGP's postretirement benefit plan costs
are pre-funded to the extent such costs are recoverable through rates. Effective
February 1, 1992, TGP began recovering through its rates the other post
retirement employee benefits
 
                                       51
<PAGE>   56
 
("OPEB") costs included in the June 2, 1993 rate case settlement agreement. To
the extent actual OPEB costs differ from the amounts funded, a regulatory asset
or liability is recorded.
 
     Several plan amendments were made effective January 1, 1998, including
increases in deductibles, increases in out-of-pocket limits, and changes to the
prescription drug provisions. These changes resulted in a $16 million decrease
in the postretirement benefits obligation.
 
     The following table sets forth the change in benefit obligation, change in
plan assets, funded status, and components of net periodic benefit cost for
other postretirement benefits. In 1998, the Company changed the measurement date
for measuring its OPEB obligations from December 31 to September 30.
Traditionally, timing of the receipt of this information has limited the
Company's ability to maximize planning and budgeting opportunities with respect
to projected costs of its various plans. The Company changed its benefit
reporting date to facilitate the planning process and gather necessary financial
reporting information in a more timely manner. Management believes the date
change is preferable to the method previously employed. This change in
measurement date has been accounted for as a change in accounting principle and
had no material cumulative effect on retirement benefit expense for the current
or prior periods.
 
<TABLE>
<CAPTION>
                                                              POSTRETIREMENT
                                                                 BENEFITS
                                                              ---------------
                                                               1998     1997
                                                              ------   ------
                                                               (IN MILLIONS)
<S>                                                           <C>      <C>
Change in benefit obligation
  Actuarial present value of benefit obligation at January
     1,.....................................................  $ 350    $ 353
  Interest cost.............................................     21       25
  Participant contributions.................................      4        5
  Amendments................................................    (16)      --
  Actuarial loss............................................     --       20
  Benefits paid.............................................    (41)     (53)
                                                              -----    -----
  Actuarial present value of benefit obligation for 1998 at
     September 30 and for 1997 at December 31...............  $ 318    $ 350
                                                              =====    =====
Change in plan assets
  Fair value of plan assets at January 1,...................  $   6    $   4
  Actual return on plan assets..............................     --        2
  Employer contributions....................................     39       49
  Participant contributions.................................      4        5
  Benefits paid.............................................    (41)     (53)
                                                              -----    -----
  Fair value of plan assets for 1998 at September 30 and for
     1997 at December 31....................................  $   8    $   7
                                                              =====    =====
Reconciliation of funded status
  Funded status for 1998 at September 30 and for 1997 at
     December 31............................................  $(310)   $(343)
  Fourth quarter contributions..............................     13       --
  Unrecognized net actuarial loss...........................     14       17
  Unrecognized prior service cost...........................    (12)      --
                                                              -----    -----
  Net accrued benefit cost at December 31...................  $(295)   $(326)
                                                              =====    =====
</TABLE>
 
                                       52
<PAGE>   57
 
     As of December 31, 1998, and 1997, the current liability portion of the
postretirement benefits was $50 million and $45 million, respectively. Benefit
obligations are based upon certain actuarial estimates as described below.
 
<TABLE>
<CAPTION>
                                                              POSTRETIREMENT BENEFITS
                                                              ------------------------
                                                                     YEAR ENDED
                                                                    DECEMBER 31,
                                                              ------------------------
                                                               1998     1997     1996
                                                              ------   ------   ------
<S>                                                           <C>      <C>      <C>
Benefit cost for the plans includes the following components
  Service cost..............................................    $--      $--     $  1
  Interest cost.............................................     21       26       25
  Net amortization of unrecognized amounts..................     (1)      (1)     (12)
                                                                ---      ---     ----
          Net periodic benefit cost.........................    $20      $25     $ 14
                                                                ===      ===     ====
</TABLE>
 
<TABLE>
<CAPTION>
                                                                 POSTRETIREMENT BENEFITS
                                                              -----------------------------
                                                              SEPTEMBER 30,    DECEMBER 31,
                                                                  1998             1997
                                                              -------------    ------------
<S>                                                           <C>              <C>
Weighted assumptions
  Discount rate.............................................      6.75%           7.00%
  Expected return on plan assets............................      7.50%           8.50%
</TABLE>
 
     Actuarial estimates for the Company's postretirement benefits plans assumed
a weighted average annual rate of increase in the per capital costs of covered
health care benefits of 10 percent through 2000, gradually decreasing to 6
percent by the year 2008. Assumed health care cost trends have a significant
effect on the amounts reported for other postretirement benefit plans. A
one-percentage point change in assumed health care cost trends would have the
following effects:
 
<TABLE>
<CAPTION>
                                                              1998    1997
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
One Percentage Point Increase
  Aggregate of Service Cost and Interest Cost for 1998 at
     September 30 and for 1997 at December 31...............  $ 0.2   $ 0.2
  Accumulated Postretirement Benefit Obligation for 1998 at
     September 30 and for 1997 at December 31...............  $ 2.6   $ 3.4
One Percentage Point Decrease
  Aggregate of Service Cost and Interest Cost for 1998 at
     September 30 and for 1997 at December 31...............  $(0.2)  $(0.2)
  Accumulated Postretirement Benefit Obligation for 1998 at
     September 30 and for 1997 at December 31...............  $(2.4)  $(3.0)
</TABLE>
 
  Retirement Savings Plan
 
     EPTPC employees participate in EPEC's defined contribution plan.
 
8. PREFERRED STOCK
 
     At December 31, 1998, EPTPC had authorized 20 million shares of preferred
stock. In November 1996, the Company issued 6 million shares of Series A
Preferred Stock. The Series A Preferred Stock is not convertible into shares of
any other class or series of stock of the Company and it has no maturity date.
Holders of shares of Series A Preferred Stock are entitled to receive cash
dividends payable quarterly at the rate of 8 1/4% of the stated value of $50 per
share. It is not redeemable at the option of EPTPC prior to December 31, 2001,
unless one or more amendments to the Internal Revenue Code are enacted that
reduce the percentage of the dividends received deduction as specified in
Section 243(a)(1) of the Internal Revenue Code. On or after December 31, 2001,
the Series A Preferred Stock is redeemable at the option of the
 
                                       53
<PAGE>   58
 
Company, in whole or in part, upon not less than 30 days' notice at a redemption
price of $50 per share, plus unpaid dividends.
 
9. SEGMENT INFORMATION
 
     The Company adopted the standards outlined in SFAS No. 131, Disclosures
about Segments of an Enterprise and Related Information, effective January 1,
1998. Accordingly, the Company has segregated its business activities into four
segments: Tennessee Gas Pipeline segment, El Paso Field Services segment, El
Paso Energy Marketing segment, and El Paso Energy International segment. These
segments are strategic business units that offer a variety of different energy
products and services. They are managed separately as each business requires
different technology and marketing strategies.
 
     The Tennessee Gas Pipeline segment, which includes the interstate pipeline
systems of TGP, Midwestern, and East Tennessee, transports natural gas to the
northeast, midwest, and mid-Atlantic sections of the U.S. including the states
of Tennessee, Virginia and Georgia as well as the New York City, Chicago, and
Boston metropolitan areas. The El Paso Field Services segment provides natural
gas gathering, products extraction, dehydration, purification, compression and
intrastate transmission services. The El Paso Energy Marketing segment markets
and trades natural gas, power, and petroleum products and participates in the
development and ownership of domestic power generation projects. The El Paso
Energy International segment develops and operates energy infrastructure
facilities worldwide.
 
     The accounting policies of the individual segments are the same as those of
the Company, as a whole, as summarized in Note 1, Basis of Presentation. Certain
business segments' earnings are largely derived from the earnings on equity
investments which are reported in Other, net in the Consolidated Statements of
Income. Accordingly, the Company evaluates segment performance based on EBIT. To
the extent practicable, results of operations for the years ended December 31,
1997 and 1996 have been reclassified to conform to the current business segment
presentation, although such results are not necessarily indicative of the
results which would have been achieved had the revised business segment
structure been in effect during that period.
 
                                       54
<PAGE>   59
 
<TABLE>
<CAPTION>
                                                                      SEGMENTS
                                                    AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1998
                                              ---------------------------------------------------------
                                              TENNESSEE   EL PASO     EL PASO       EL PASO
                                                 GAS       FIELD      ENERGY        ENERGY
                                              PIPELINE    SERVICES   MARKETING   INTERNATIONAL   TOTAL
                                              ---------   --------   ---------   -------------   ------
                                                                    (IN MILLIONS)
<S>                                           <C>         <C>        <C>         <C>             <C>
Revenue from external customers
  Domestic..................................   $  728       $194      $4,000         $ --        $4,922
  Foreign...................................       --         --         323           58           381
Intersegment revenue........................       38         59          17           --           114
Depreciation and amortization...............      143         43           3            9           198
Operating income............................      332         63           5          (28)          372
Other, net..................................       26         15           4           53            98
Earnings before interest and taxes..........      358         78           9           25           470
Assets
  Domestic..................................    5,783        932         598          311         7,624
  Foreign...................................       --         --          73          581           654
Capital expenditures........................      138        104           1          119           362
Equity investments..........................       74         69          --          436           579
</TABLE>
 
<TABLE>
<CAPTION>
                                                                      SEGMENTS
                                                    AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1997
                                              ---------------------------------------------------------
                                              TENNESSEE   EL PASO     EL PASO       EL PASO
                                                 GAS       FIELD      ENERGY        ENERGY
                                              PIPELINE    SERVICES   MARKETING   INTERNATIONAL   TOTAL
                                              ---------   --------   ---------   -------------   ------
                                                                    (IN MILLIONS)
<S>                                           <C>         <C>        <C>         <C>             <C>
Revenue from external customers
  Domestic..................................   $  765       $360      $3,757          $--        $4,882
  Foreign...................................       --         --         218           13           231
Intersegment revenue........................       33         20          20           --            73
Depreciation and amortization...............      137         33           4            1           175
Operating income............................      304         66         (31)         (24)          315
Other, net..................................       14          8           3           26            51
Earnings before interest and taxes..........      318         74         (28)           2           366
Assets
  Domestic..................................    5,826        878         804          185         7,693
  Foreign...................................       --         --          16          238           254
Capital expenditures........................      111         62           8           21           202
Equity investments..........................       64         24          44          241           373
</TABLE>
 
<TABLE>
<CAPTION>
                                                                      SEGMENTS
                                                       FOR THE YEAR ENDED OF DECEMBER 31, 1996
                                              ---------------------------------------------------------
                                              TENNESSEE   EL PASO     EL PASO       EL PASO
                                                 GAS       FIELD      ENERGY        ENERGY
                                              PIPELINE    SERVICES   MARKETING   INTERNATIONAL   TOTAL
                                              ---------   --------   ---------   -------------   ------
                                                                    (IN MILLIONS)
<S>                                           <C>         <C>        <C>         <C>             <C>
Revenue from external customers
  Domestic.................................     $646        $317      $3,903          $37        $4,903
Intersegment revenue.......................      151          25          14           --           190
Depreciation and amortization..............      120          32           7            9           168
Operating income...........................      253          42          (5)          (6)          284
Other, net.................................       58          10           4           12            84
Earnings before interest and taxes.........      311          52          (1)           6           368
</TABLE>
 
                                       55
<PAGE>   60
 
     The reconciliations of revenues for reportable segments to total
consolidated revenues are presented below.
 
<TABLE>
<CAPTION>
                                                                 FOR THE YEAR ENDED
                                                                    DECEMBER 31,
                                                              ------------------------
                                                               1998     1997     1996
                                                              ------   ------   ------
                                                                   (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
Total revenues for segments.................................  $5,417   $5,186   $5,093
Other revenues..............................................       5        4      105
Elimination of intersegment revenue.........................    (114)     (73)    (190)
                                                              ------   ------   ------
          Total consolidated revenues.......................  $5,308   $5,117   $5,008
                                                              ======   ======   ======
</TABLE>
 
     The reconciliations of EBIT to income before income taxes are presented
below.
 
<TABLE>
<CAPTION>
                                                                 FOR THE YEAR ENDED
                                                                    DECEMBER 31,
                                                              ------------------------
                                                               1998     1997     1996
                                                              ------   ------   ------
                                                                   (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
Total EBIT for segments.....................................  $  470   $  366   $  368
Corporate expenses, net.....................................      (1)      22       11
Interest and debt expense...................................     152      141      151
                                                              ------   ------   ------
          Income before income taxes........................  $  319   $  203   $  206
                                                              ======   ======   ======
</TABLE>
 
     The reconciliations of assets for reportable segments to total consolidated
assets are presented below.
 
<TABLE>
<CAPTION>
                                                                   AS OF DECEMBER 31,
                                                                   -------------------
                                                                     1998       1997
                                                                   --------   --------
                                                                      (IN MILLIONS)
<S>                                                                 <C>         <C>
Total assets for segments........................................   $8,278      $7,947
Other assets and eliminations....................................     (752)       (384)
                                                                    ------      ------
          Total consolidated assets..............................   $7,526      $7,563
                                                                    ======      ======
</TABLE>
 
     The reconciliations of other, net for reportable segments to total
consolidated other, net are presented below.
 
<TABLE>
<CAPTION>
                                                                 FOR THE YEAR ENDED
                                                                    DECEMBER 31,
                                                              ------------------------
                                                               1998     1997     1996
                                                              ------   ------   ------
                                                                   (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
Total other, net for segments...............................  $   98   $   51   $   84
Corporate other, net........................................      16        2       34
Gain or (loss) on sale of assets............................     (19)      (1)     (35)
                                                              ------   ------   ------
          Total consolidated other, net.....................  $   95   $   52   $   83
                                                              ======   ======   ======
</TABLE>
 
     The Company did not have gross revenue from any customer equal to, or in
excess of, ten percent of consolidated operating revenue for the years ended
December 31, 1998, 1997, and 1996.
 
10. INVENTORIES
 
     Inventories consisted of the following at December 31:
 
<TABLE>
<CAPTION>
                                                                     1998        1997
                                                                    ------      ------
                                                                        (IN MILLIONS)
<S>                                                                 <C>         <C>
Materials and supplies............................................  $   17      $   16
Gas in storage....................................................       4          25
                                                                    ------      ------
          Total...................................................  $   21      $   41
                                                                    ======      ======
</TABLE>
 
                                       56
<PAGE>   61
 
11. PROPERTY, PLANT, AND EQUIPMENT
 
     Property, plant and equipment consisted of the following at December 31:
 
<TABLE>
<CAPTION>
                                                               1998      1997
                                                              ------    ------
                                                               (IN MILLIONS)
<S>                                                           <C>       <C>
Property, plant, and equipment, at cost
  Tennessee Gas Pipeline....................................  $2,438    $2,289
  El Paso Field Services....................................   1,117     1,022
  El Paso Energy Marketing..................................      15        78
  El Paso Energy International..............................     283        79
  Corporate and Other.......................................      73        69
                                                              ------    ------
                                                               3,926     3,537
Less accumulated depreciation and depletion.................     577       452
                                                              ------    ------
                                                               3,349     3,085
Additional acquisition cost assigned to utility plant, net
  of accumulated amortization...............................   2,400     2,424
                                                              ------    ------
Total property, plant, and equipment, net...................  $5,749    $5,509
                                                              ======    ======
</TABLE>
 
     Current FERC policy does not permit the Company to recover amounts in
excess of original cost allocated in purchase accounting to its regulated
operations through rates.
 
12. INVESTMENT IN AFFILIATED COMPANIES (UNAUDITED)
 
     The Company holds investments in various affiliates which are accounted for
on the equity method of accounting. The principal equity method investments are
the Company's investments in international pipelines, interstate pipelines,
power generation plants, gathering systems and natural gas storage facilities.
 
     Summarized financial information of the Company's proportionate share of 50
percent or less owned companies accounted for by the equity method of accounting
is as follows:
 
<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31,
                                                              -----------------------
COMPANIES OWNED 50% OR LESS                                   1998     1997     1996
---------------------------                                   -----    -----    -----
                                                                   (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
Operating results data:
  Revenues and other income.................................  $190     $130      $98
  Costs and expenses........................................   145      103       68
                                                              ----     ----      ---
  Net income................................................  $ 45     $ 27      $30
                                                              ====     ====      ===
</TABLE>
 
<TABLE>
<CAPTION>
                                                               DECEMBER 31,
                                                              ---------------
                                                               1998     1997
                                                              ------   ------
                                                               (IN MILLIONS)
<S>                                                           <C>      <C>
Financial position data:
  Current assets............................................  $  177   $   78
  Non-current assets........................................   1,768    1,033
  Short-term debt...........................................      39       25
  Other current liabilities.................................      70       50
  Long-term debt............................................   1,028      640
  Other non-current liabilities.............................     166       67
  Equity in net assets......................................     642      329
</TABLE>
 
                                       57
<PAGE>   62
 
13. SUPPLEMENTAL CASH FLOW INFORMATION
 
     The following table contains supplemental cash flow information for the
years ended December 31:
 
<TABLE>
<CAPTION>
                                                             1998     1997     1996
                                                             -----    -----    -----
                                                                  (IN MILLIONS)
<S>                                                          <C>      <C>      <C>
Interest...................................................  $ 186    $ 141    $ 232
Income tax payments (refunds)..............................    (91)     (79)     289
</TABLE>
 
14. TRANSACTIONS WITH AFFILIATES
 
  General and Administrative
 
     In 1998, EPEC allocated certain general and administrative expenses to the
Company. The allocation is based on the estimated level of effort devoted to the
Company's operations and relative size based on revenues, gross property and
payroll. In 1996 and 1997, the Company performed most of its own administrative
functions, and therefore, allocated general and administrative expenses were
lower than for 1998. In 1996, the Company received an allocation of costs for
these services from Old Tenneco. Costs allocated to the Company included in
operation and maintenance expense in the Consolidated Income Statements were
$176 million, $35 million, and $28 million for the years ended December 31,
1998, 1997, and 1996, respectively.
 
     The Company's management believes the method for allocating corporate
general and administrative expenses is reasonable and that total general and
administrative expenses reflected in the accompanying pre-acquisition combined
statements of income are reasonable when compared with the total general and
administrative costs the Company would have incurred on a stand-alone basis.
 
  Notes and Advances Receivable or Payable with Affiliates
 
     For the years 1996 cash contributions from (distributions to) affiliates in
the Statements of Changes in Consolidated Stockholders' Equity and Combined
Equity consist of net cash changes in notes and advances receivable or payable
between the Company and the industrial business and shipbuilding business which
have been included in combined equity. Historically, Old Tenneco has utilized
notes and advances to centrally manage cash funding requirements for its
consolidated group.
 
     The "Note payable to EPEC" balance at December 31, 1998 and 1997 relates to
an interest-bearing demand loan first made to TGP from EPEC in December 1996
subsequent to the Merger.
 
                                       58
<PAGE>   63
 
15. QUARTERLY FINANCIAL DATA (UNAUDITED)
 
<TABLE>
<CAPTION>
                                                              OPERATING    OPERATING     NET
                          QUARTER                             REVENUES      INCOME      INCOME
                          -------                             ---------    ---------    ------
                                                                       (IN MILLIONS)
<S>                                                           <C>          <C>          <C>
1998 1st....................................................   $1,505        $105        $ 57
      2nd...................................................    1,172          64          39
      3rd...................................................    1,497          63          38
      4th...................................................    1,134         125          91
                                                               ------        ----        ----
                                                               $5,308        $357        $225
                                                               ======        ====        ====
1997 1st....................................................   $1,702        $ 79        $ 32
      2nd...................................................      852          57          23
      3rd...................................................    1,121          70          35
      4th...................................................    1,442          85          40
                                                               ------        ----        ----
                                                               $5,117        $291        $130
                                                               ======        ====        ====
</TABLE>
 
                                       59
<PAGE>   64
 
                       REPORT OF INDEPENDENT ACCOUNTANTS
 
To the Board of Directors and Stockholders of
El Paso Tennessee Pipeline Co.:
 
     In our opinion, the consolidated financial statements listed in the index
appearing under Item 14. (a) 1. present fairly, in all material respects, the
consolidated financial position of El Paso Tennessee Pipeline Co. as of December
31, 1998 and 1997, and the consolidated results of its operations and its cash
flows for each of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles. In addition, in our
opinion, the financial statement schedule listed in the index appearing under
Item 14. (a) 2. presents fairly, in all material respects, the information set
forth therein when read in conjunction with the related consolidated financial
statements. These financial statements and the financial statement schedule are
the responsibility of the Company's management; our responsibility is to express
an opinion on these financial statements and the financial statement schedule
based on our audits. We conducted our audits of these statements in accordance
with generally accepted auditing standards which require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for the opinions expressed
above.
 
PricewaterhouseCoopers LLP
 
Houston, Texas
March 9, 1999
 
                                       60
<PAGE>   65
 
                                  SCHEDULE II
 
                         EL PASO TENNESSEE PIPELINE CO.
                       VALUATION AND QUALIFYING ACCOUNTS
 
                 YEARS ENDED DECEMBER 31, 1998, 1997, AND 1996
 
                                 (IN MILLIONS)
 
<TABLE>
<CAPTION>
                COLUMN A                   COLUMN B           COLUMN C            COLUMN D    COLUMN E
                --------                   --------    -----------------------    --------    --------
                                          BALANCE AT   CHARGED TO   CHARGED TO                BALANCE
                                          BEGINNING    COSTS AND      OTHER                    AT END
              DESCRIPTION                  OF YEAR      EXPENSES     ACCOUNTS    DEDUCTIONS   OF YEAR
              -----------                 ----------   ----------   ----------   ----------   --------
<S>                                       <C>          <C>          <C>          <C>          <C>
1998
  Allowance for doubtful accounts.......     $ 47         $ 11         $ 4          $ 29(a)     $33
  Valuation allowance on deferred tax
     assets.............................        8           --           4             7          5
1997
  Allowance for doubtful accounts.......     $ 63         $ 33         $ 1          $ 50(a)     $47
  Valuation allowance on deferred tax
     assets.............................       --           --           8(b)         --          8
1996
  Allowance for doubtful accounts.......     $ 59         $ 30         $--          $ 26(a)     $63
  Valuation allowance on deferred tax
     assets (c).........................      117          (38)         --            79         --
</TABLE>
 
---------------
 
(a) Primarily accounts written off.
 
(b) Due to acquisition of Gulf States Gas Pipeline Company.
 
(c) The Company had potential tax benefits of $117 million at December 31, 1995,
    which were not recognized in the statement of income when generated. These
    benefits resulted primarily from U.S. capital loss carryforwards which were
    available to offset future capital gains. During 1996, these capital loss
    carryforwards were utilized to offset taxes on capital gain transactions of
    the Company and certain Old Tenneco affiliates.
 
                                       61
<PAGE>   66
 
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
 
     The information appearing under the caption "Proposal No. 1 -- Nominee for
Election of Director by Series A Preferred Stockholders" and "Section 16(a)
Beneficial Ownership Reporting Compliance" in EPTPC's proxy statement for the
1999 Annual Meeting of Stockholders is incorporated herein by reference.
Information regarding executive officers of EPTPC is presented in Item 1 of this
Form 10-K under the caption "Executive Officers of the Registrant" and is
incorporated herein by reference.
 
ITEM 11. EXECUTIVE COMPENSATION
 
     Information appearing under the caption "Executive Compensation" in EPTPC's
proxy statement for the 1999 Annual Meeting of Stockholders is incorporated
herein by reference.
 
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
 
     Information appearing under the captions "Security Ownership of Beneficial
Owners and Management of the Company" and "Security Ownership of a Beneficial
Owner and Management of EPEC" in EPTPC's proxy statement for the 1999 Annual
Meeting of Stockholders is incorporated herein by reference.
 
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
 
     Information appearing under the caption "Relationship with El Paso Energy
Corporation" in EPTPC's proxy statement for the 1999 Annual Meeting of
Stockholders is incorporated herein by reference.
 
                                       62
<PAGE>   67
 
                                    PART IV
 
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
 
     (a) The following documents are filed as a part of this report:
 
      1. Financial statements.
 
     The following consolidated and combined financial statements of the Company
are included in Part II, Item 8 of this report:
 
<TABLE>
<CAPTION>
                                                                   PAGE
                                                                   ----
    <S>                                                            <C>
         Consolidated Statements of Income......................     34
         Consolidated Balance Sheets............................     35
         Consolidated Statements of Cash Flows..................     36
         Statements of Changes in Consolidated Stockholders'
           Equity and Combined Equity...........................     37
         Consolidated Statements of Comprehensive Income........     38
         Notes to Consolidated Financial Statements.............     39
         Report of independent accountants......................     60

      2. Financial statement schedules and supplementary 
         information required to be submitted.
 
         Schedule II -- Valuation and qualifying accounts.......     61
         Schedules other than that listed above are omitted
         because they are not applicable
 
      3. Exhibit list...........................................     64
</TABLE>
 
     (b) Reports on Form 8-K:
 
     On October 16, 1998, EPTP filed a report under Item 5 on Form 8-K, dated
October 16, 1998 with respect to the tax-free internal reorganization.
 
                                       63
<PAGE>   68
 
                         EL PASO TENNESSEE PIPELINE CO.
 
                                  EXHIBIT LIST
                               DECEMBER 31, 1998
 
     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.
 
<TABLE>
<CAPTION>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
         2.A             -- Amended and Restated Merger Agreement dated as of June
                            19, 1996, among EPNG, El Paso Merger Company and EPTPC
                            (Exhibit 2.A to EPNG's Registration Statement on Form S-4
                            filed August 27, 1996, File No. 333-10911).
         2.B             -- Distribution Agreement, dated as of November 1, 1996,
                            among EPTPC, New Tenneco Inc. and Newport News
                            Shipbuilding Inc. (Exhibit 2.2 to EPNG's Form 8-K filed
                            December 26, 1996, File No. 1-2700); Amendment No. 1 to
                            Distribution Agreement entered into as of December 11,
                            1996, by and among EPTPC, New Tenneco Inc. and Newport
                            News Shipbuilding Inc. (Exhibit 2.3 to EPNG's Form 8-K/A
                            filed January 21, 1997, File No. 1-2700).
         3.A             -- Certificate of Incorporation as amended and supplemented
                            as of March 1, 1995 (Exhibit 3(a)(1) to EPTPC Form 10-K
                            for 1994, File No. 1-9864); Certificate of Retirement of
                            Preferred Stock Redeemed or Purchased, dated February 16,
                            1996; Certificate of Elimination of the Series A
                            Cumulative Preferred Stock of Tenneco Inc. dated February
                            27, 1996; Certificate of Elimination of the Variable Rate
                            Preferred Stock of Tenneco Inc. dated February 27, 1996;
                            Certificate of Elimination of the Participating Preferred
                            Stock of Tenneco Inc. dated February 27, 1996;
                            Certificate of Designation, Preferences and Rights of
                            8 1/4% Cumulative Junior Preferred Stock, Series A, dated
                            November 18, 1996; Certificate of Amendment of
                            Certificate of Incorporation, dated December 11, 1996;
                            Certificate of Merger dated December 11, 1996; and
                            Certificate of Designation, Preferences and Rights of
                            8 1/2% Cumulative Junior Preferred Stock, Series B, dated
                            March 5, 1997 (Exhibit 3.A to EPTPC's Form 10-K for 1996,
                            File No. 1-9864); Certificate of Designation, Preferences
                            and Rights of 6 1/4% Cumulative Junior Preferred Stock,
                            Series C, dated March 4, 1998 (Exhibit 3.A.1 to EPTPC's
                            Form 10-K for 1997, File No. 1-9864).
        *3.A.1           -- Certificate of Elimination of 8 1/2% Cumulative Junior
                            Preferred Stock, Series B, dated January 14, 1999,
                            Certificate of Elimination of 6 1/4% Cumulative Junior
                            Preferred Stock, Series C, dated January 14, 1999.
         3.B             -- By-laws of EPTPC, as amended March 1, 1998 (Exhibit 3.B
                            to EPTPC's Form 10-K for 1997, File No. 1-9864).
         4.A             -- Indenture dated as of March 4, 1997, between TGP and The
                            Chase Manhattan Bank (Exhibit 4.1 to EPTPC's Form 10-K
                            for 1997, File No. 1-9864); First Supplemental Indenture
                            dated as of March 13, 1997, between TGP and The Chase
                            Manhattan Bank (Exhibit 4.2 to EPTPC's Form 10-K for
                            1997, File No. 1-9864); Second Supplemental Indenture
                            dated as of March 13, 1997, between TGP and The Chase
                            Manhattan Bank (Exhibit 4.3 to EPTPC's Form 10-K for
                            1997, File No. 1-9864); Third Supplemental Indenture
                            dated as of March 13, 1997, between TGP and The Chase
                            Manhattan Bank (Exhibit 4.4 to EPTPC's Form 10-K for
                            1997, File No. 1-9864); Fourth Supplemental Indenture
                            dated as of October 9, 1998, between TGP and The Chase
                            Manhattan Bank (Exhibit 4.2 to TGP's Form 8-K filed
                            October 9, 1998, File No. 1-4101).
       *18               -- Letter Regarding Change in Accounting Principles.
       *21               -- List of Subsidiaries.
       *27               -- Financial Data Schedule.
</TABLE>
 
                                       64
<PAGE>   69
 
UNDERTAKING
 
     The undersigned Registrant hereby undertakes, pursuant to Regulation S-K,
Item 601(b), paragraph (4)(iii), to furnish to the Securities and Exchange
Commission upon request all constituent instruments defining the rights of
holders of long-term debt of Registrant and its consolidated subsidiaries not
filed herewith for the reason that the total amount of securities authorized
under any of such instruments does not exceed 10 percent of the total
consolidated assets of Registrant and its consolidated subsidiaries.
 
                                       65
<PAGE>   70
 
                                   SIGNATURES
 
     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, as amended, El Paso Tennessee Pipeline Co. has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly
authorized on the 17th day of March 1999.
 
                                          EL PASO TENNESSEE PIPELINE CO.
 
                                          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 1933, as
amended, this report has been signed below by the following persons on behalf of
El Paso Tennessee Pipeline Co. and in the capacities and on the dates as
indicated.
 
<TABLE>
<CAPTION>
                 SIGNATURE                                  TITLE                          DATE
                 ---------                                  -----                          ----
<C>                                           <S>                                <C>
 
            /s/ WILLIAM A. WISE               Chairman of the Board, President,            March 17, 1999
--------------------------------------------  Chief Executive Officer and
              William A. Wise                 Director
 
            /s/ H. BRENT AUSTIN               Executive Vice President, Chief              March 17, 1999
--------------------------------------------  Financial Officer and Director
              H. Brent Austin
 
           /s/ JOEL RICHARDS III              Executive Vice President and                 March 17, 1999
--------------------------------------------  Director
             Joel Richards III
 
           /s/ BRITTON WHITE JR.              Executive Vice President, General            March 17, 1999
--------------------------------------------  Counsel and Director
             Britton White Jr.
 
           /s/ JEFFREY I. BEASON              Vice President, Controller and               March 17, 1999
--------------------------------------------  Director
             Jeffrey I. Beason
 
           /s/ KENNETH L. SMALLEY             Director                                     March 17, 1999
--------------------------------------------
             Kenneth L. Smalley
</TABLE>
 
                                       66
<PAGE>   71
 
                               INDEX TO EXHIBITS
 
     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.
 
<TABLE>
<CAPTION>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
         2.A             -- Amended and Restated Merger Agreement dated as of June
                            19, 1996, among EPNG, El Paso Merger Company and EPTPC
                            (Exhibit 2.A to EPNG's Registration Statement on Form S-4
                            filed August 27, 1996, File No. 333-10911).
         2.B             -- Distribution Agreement, dated as of November 1, 1996,
                            among EPTPC, New Tenneco Inc. and Newport News
                            Shipbuilding Inc. (Exhibit 2.2 to EPNG's Form 8-K filed
                            December 26, 1996, File No. 1-2700); Amendment No. 1 to
                            Distribution Agreement entered into as of December 11,
                            1996, by and among EPTPC, New Tenneco Inc. and Newport
                            News Shipbuilding Inc. (Exhibit 2.3 to EPNG's Form 8-K/A
                            filed January 21, 1997, File No. 1-2700).
         3.A             -- Certificate of Incorporation as amended and supplemented
                            as of March 1, 1995 (Exhibit 3(a)(1) to EPTPC Form 10-K
                            for 1994, File No. 1-9864); Certificate of Retirement of
                            Preferred Stock Redeemed or Purchased, dated February 16,
                            1996; Certificate of Elimination of the Series A
                            Cumulative Preferred Stock of Tenneco Inc. dated February
                            27, 1996; Certificate of Elimination of the Variable Rate
                            Preferred Stock of Tenneco Inc. dated February 27, 1996;
                            Certificate of Elimination of the Participating Preferred
                            Stock of Tenneco Inc. dated February 27, 1996;
                            Certificate of Designation, Preferences and Rights of
                            8 1/4% Cumulative Junior Preferred Stock, Series A, dated
                            November 18, 1996; Certificate of Amendment of
                            Certificate of Incorporation, dated December 11, 1996;
                            Certificate of Merger dated December 11, 1996; and
                            Certificate of Designation, Preferences and Rights of
                            8 1/2% Cumulative Junior Preferred Stock, Series B, dated
                            March 5, 1997 (Exhibit 3.A to EPTPC's Form 10-K for 1996,
                            File No. 1-9864); Certificate of Designation, Preferences
                            and Rights of 6 1/4% Cumulative Junior Preferred Stock,
                            Series C, dated March 4, 1998 (Exhibit 3.A.1 to EPTPC's
                            Form 10-K for 1997, File No. 1-9864).
        *3.A  .1         -- Certificate of Elimination of 8 1/2% Cumulative Junior
                            Preferred Stock, Series B, dated January 14, 1999,
                            Certificate of Elimination of 6 1/4% Cumulative Junior
                            Preferred Stock, Series C, dated January 14, 1999.
         3.B             -- By-laws of EPTPC, as amended March 1, 1998 (Exhibit 3.B
                            to EPTPC's Form 10-K for 1997, File No. 1-9864).
         4.A             -- Indenture dated as of March 4, 1997, between TGP and The
                            Chase Manhattan Bank (Exhibit 4.1 to EPTPC's Form 10-K
                            for 1997, File No. 1-9864); First Supplemental Indenture
                            dated as of March 13, 1997, between TGP and The Chase
                            Manhattan Bank (Exhibit 4.2 to EPTPC's Form 10-K for
                            1997, File No. 1-9864); Second Supplemental Indenture
                            dated as of March 13, 1997, between TGP and The Chase
                            Manhattan Bank (Exhibit 4.3 to EPTPC's Form 10-K for
                            1997, File No. 1-9864); Third Supplemental Indenture
                            dated as of March 13, 1997, between TGP and The Chase
                            Manhattan Bank (Exhibit 4.4 to EPTPC's Form 10-K for
                            1997, File No. 1-9864); Fourth Supplemental Indenture
                            dated as of October 9, 1998, between TGP and The Chase
                            Manhattan Bank (Exhibit 4.2 to TGP's Form 8-K filed
                            October 9, 1998, File No. 1-4101).
       *18               -- Letter Regarding Change in Accounting Principles.
       *21               -- List of Subsidiaries.
       *27               -- Financial Data Schedule.
</TABLE>