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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, 1997
 
                                       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 1-2700
 
                          EL PASO NATURAL GAS COMPANY
             (Exact Name of Registrant as Specified in Its Charter)
 
<TABLE>
<S>                                                 <C>
                     DELAWARE                                           74-0608280
         (State or Other Jurisdiction of                             (I.R.S. Employer
          Incorporation or Organization)                           Identification No.)
 
             EL PASO ENERGY BUILDING
                  1001 LOUISIANA
                  HOUSTON, TEXAS                                          77002
     (Address of Principal Executive Offices)                           (Zip Code)
</TABLE>
 
       REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 757-2131
 
          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>
Common Stock, par value $3 per          New York Stock Exchange
  share...............................
Preferred Stock Purchase Rights.......  New York Stock Exchange
9.45% Notes due 1999..................  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]  [ ].
 
     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 of the voting stock (which consists solely of shares
of common stock) held by non-affiliates of the registrant as of March 16, 1998,
computed by reference to the closing sale price of the registrant's common stock
on the New York Stock Exchange on such date: $4,046,351,130.
 
     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 $3 per share. Shares outstanding on March 16, 1998:
60,224,761
 
                      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 Natural Gas Company's definitive Proxy Statement for the
1998 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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                          EL PASO NATURAL GAS COMPANY
 
                               TABLE OF CONTENTS
 
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                                    CAPTION                             PAGE
                                    -------                             ----
<S>                                                                     <C>
Glossary..............................................................   ii
 
                                     PART I
Item 1.   Business....................................................    1
Item 2.   Properties..................................................   13
Item 3.   Legal Proceedings...........................................   13
Item 4.   Submission of Matters to a Vote of Security Holders.........   14
 
                                    PART II
Item 5.   Market for Registrant's Common Equity and Related
            Stockholder Matters.......................................   15
Item 6.   Selected Financial Data.....................................   16
Item 7.   Management's Discussion and Analysis of Financial Condition
            and Results of Operations.................................   17
          Risk Factors -- Cautionary Statement for Purposes of the
            "Safe Harbor" Provisions of the Private Securities 
            Litigation Reform Act of 1995.............................   30
Item 7A.  Quantitative and Qualitative Disclosures About Market
            Risk......................................................   33
Item 8.   Financial Statements and Supplementary Data.................   34
Item 9.   Changes in and Disagreements with Accountants on Accounting
            and Financial Disclosure..................................   69
 
                                    PART III
Item 10.  Directors and Executive Officers of the Registrant..........   69
Item 11.  Executive Compensation......................................   69
Item 12.  Security Ownership of Certain Beneficial Owners and
            Management................................................   69
Item 13.  Certain Relationships and Related Transactions..............   69
 
                                    PART IV
Item 14.  Exhibits, Financial Statement Schedules, and Reports on Form
            8-K.......................................................   69
          Signatures..................................................   72
</TABLE>
 
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                                    GLOSSARY
 
     The following abbreviations, acronyms, or defined terms used in this Form
10-K are defined below:
 
<TABLE>
<S>                                 <C>
ALJ...............................  Administrative Law Judge
BBtu..............................  Billion British thermal units
BBtu/d............................  Billion British thermal units per day
Bcf...............................  Billion cubic feet
Bcf/d.............................  Billion cubic feet per day
Board.............................  Board of directors of El Paso Natural Gas Company
BR................................  Burlington Resources Inc.
CAPSA.............................  Companias Asociadas Petroleras SA, a privately held integrated
                                    energy company in Argentina
CFE...............................  Comision Federal de Electricidad, the Mexican
                                    government-owned electric utility
Company...........................  El Paso Natural Gas Company, now doing business as
                                    El Paso Energy Corporation, and its subsidiaries, unless the
                                    context otherwise requires
Cornerstone.......................  Cornerstone Natural Gas, Inc., a wholly owned subsidiary of El Paso
                                    Field Services Company
Court of Appeals..................  United States Court of Appeals for the District of Columbia Circuit
Distributions.....................  Various intercompany transfers and distributions which
                                    restructured, divided and separated the business, assets and
                                    liabilities of Old Tenneco and its subsidiaries so that all the
                                    assets, liabilities and operations related to the automotive parts,
                                    packaging and administrative services businesses and the
                                    shipbuilding business were spun-off to Old Tenneco's then existing
                                    common stockholders
East Tennessee....................  East Tennessee Natural Gas Company, a wholly owned subsidiary of
                                    Tennessee Gas Pipeline Company
Edison............................  Southern California Edison Company
EPA...............................  United States Environmental Protection Agency
EPEI..............................  El Paso Energy International Company, a wholly owned subsidiary of
                                    El Paso Natural Gas Company
EPEM..............................  El Paso Energy Marketing Company, a wholly owned subsidiary of El
                                    Paso Natural Gas Company, unless the context requires otherwise
EPFS..............................  El Paso Field Services Company, a wholly owned subsidiary of El
                                    Paso Natural Gas Company
EPG...............................  El Paso Natural Gas Company, unless the context otherwise requires
EPNC..............................  El Paso New Chaco Company, a wholly owned subsidiary of El Paso
                                    Natural Gas Company
EPTPC.............................  El Paso Tennessee Pipeline Co. (formerly Tenneco Inc.), an indirect
                                    subsidiary of El Paso Natural Gas Company
FERC..............................  Federal Energy Regulatory Commission
GSR...............................  Gas supply realignment
IRS...............................  Internal Revenue Service
Merger............................  The acquisition of El Paso Tennessee Pipeline Co. by
                                    El Paso Natural Gas Company in December 1996
Mgal/d............................  Thousand gallons per day
Midwestern........................  Midwestern Gas Transmission Company, a wholly owned indirect
                                    subsidiary of Tennessee Gas Pipeline Company
</TABLE>
 
                                       ii
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<TABLE>
<S>                                          <C>
MMcf/d.....................................  Million cubic feet per day
Mdth/d.....................................  Thousand decatherms per day
MPC........................................  Mojave Pipeline Company, a wholly owned indirect partnership of El
                                             Paso Natural Gas Company
MW(s)......................................  Megawatt(s)
New Tenneco................................  Tenneco Inc., subsequent to the Merger and Distributions, consisting
                                             of the automotive parts, packaging and administrative services
                                             businesses
NGC........................................  NGC Corporation
NGLs.......................................  Natural gas liquids
Odd-Lot Holders............................  Stockholders of El Paso Natural Gas Company owning beneficially fewer
                                             than 100 shares of El Paso Natural Gas Company's common stock
Old Tenneco................................  Tenneco Inc. (renamed El Paso Tennessee Pipeline Co.), prior to its
                                             acquisition by the Company
OPEB.......................................  Other Postretirement Employee Benefits
OTC........................................  Over-the-counter
PCB(s).....................................  Polychlorinated biphenyl(s)
Pemex......................................  Pemex Gas y Petroquimica Basica, a Mexican state-owned company
PG&E.......................................  Pacific Gas & Electric Company
Plan.......................................  Dividend Reinvestment and Common Stock Purchase Plan
PLN........................................  Perusahaan Listrik Negara, the Indonesian government owned electric
                                             utility
Premier....................................  Premier Gas Company, a wholly owned subsidiary of El Paso Energy
                                             Marketing Company
Program....................................  Continuous Odd-Lot Stock Sales Program
PRP(s).....................................  Potentially Responsible Party(ies)
SAR(s).....................................  Stock Appreciation Right(s)
SEC........................................  Securities and Exchange Commission
SFAS.......................................  Statement of Financial Accounting Standards
SoCal......................................  Southern California Gas Company
Tcf........................................  Trillion cubic feet
TGP........................................  Tennessee Gas Pipeline Company, a wholly owned subsidiary of El Paso
                                             Tennessee Pipeline Co.
TransAmerican..............................  TransAmerican Natural Gas Corporation
Transwestern...............................  Transwestern Pipeline Company
</TABLE>
 
                                       iii
<PAGE>   5
 
                                     PART I
 
ITEM 1. BUSINESS
 
                                    GENERAL
 
     EPG, a Delaware corporation incorporated in 1928, owns and operates one of
the nation's largest integrated natural gas systems, with natural gas pipelines
extending from coast to coast. EPG's principal operations include the interstate
and intrastate transportation, gathering and processing of natural gas; the
marketing of natural gas and other commodities; and the development and
operation of energy infrastructure facilities worldwide. EPG is conducting
business under the name El Paso Energy Corporation.
 
     The Company owns or has interests in over 28,200 miles of interstate and
intrastate pipeline systems connecting the nation's principal natural gas supply
regions to four of the largest consuming regions in the United States, namely
the Gulf Coast, California, the Northeast and the Midwest. The Company's natural
gas transmission operations include one of the nation's largest mainline natural
gas transmission systems which is comprised of five interstate pipeline systems:
the EPG system, the TGP system, the Midwestern system, the East Tennessee
system, and the MPC system. Intrastate transmission operations are conducted
through the Company's interests in Oasis Pipe Line Company, Channel Industries
Gas Pipeline Company, and Gulf States Gas Pipeline Company.
 
     In addition to its interstate and intrastate transmission services, EPG
provides services including natural gas gathering, products extraction,
dehydration, purification and compression. These operations include
approximately 8,750 miles of gathering systems, 240,000 horsepower of
compression and ownership of or interests in 25 natural gas processing and
treating facilities located in the most prolific and active production areas of
the U.S. (including the San Juan, Anadarko and Permian Basins and East Texas,
South Texas, Louisiana and the Gulf of Mexico). EPG's marketing activities
include the marketing and trading of natural gas, NGLs, power, crude oil and
refined products, as well as providing integrated price risk management services
associated with these commodities, and participating in the development and
ownership of domestic power generating facilities.
 
     The Company's international activities are focused on the development and
operation of international energy infrastructure projects and include ownership
interests in (i) three major existing natural gas transmission systems in
Australia, (ii) natural gas transmission systems and power generation facilities
currently in operation or under construction in Argentina, Bolivia, Brazil,
Chile, Czech Republic, Hungary, Indonesia, Mexico, Pakistan and Peru, and (iii)
three operating domestic power generation plants.
 
     In March 1998, the Company and DeepTech International Inc. ("Deeptech")
entered into a definitive agreement whereby the Company will acquire DeepTech as
well as DeepTech's combined ownership interest in Leviathan Gas Pipeline
Partners, L.P. ("Levianthan"). Leviathan is a publicly traded partnership that
produces, processes, gathers, transports and markets oil and gas located in the
offshore Gulf of Mexico. In connection with the acquisition, the Company will
acquire the 15 percent minority equity interest in the holding company through
which DeepTech owns its Leviathan interests. After the transactions, the Company
will own 100 percent of the general partner of Leviathan and a 27.3 percent
effective ownership interest in Leviathan. Each holder of DeepTech common stock
will receive as consideration $14 per share either in cash or EPG common stock,
at such holder's election, subject to a minimum and maximum exchange ratio of
approximately 0.1867 and 0.28 shares, respectively, of EPG common stock for each
share of DeepTech common stock. The acquisition will be accounted for as a
purchase, with a total purchase price of approximately $450 million. Completion
of the transactions is subject to various conditions including the receipt of
required regulatory and stockholder approvals and other customary conditions,
and no assurance can be given that the transactions will be successfully
completed.
 
     Leviathan is the largest independent gatherer of natural gas in the Gulf of
Mexico and has interests in pipeline systems which transported more than 2.8
Bcf/d in 1997. These pipeline systems, which cover a large portion of the Outer
Continental Shelf and access the prolific Deepwater Trend of the Gulf of Mexico,
include
 
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<PAGE>   6
 
the High Island Offshore system, the U-T Offshore system, the Stingray Pipeline
system, the Nautilus/Manta Ray Offshore system, the Viosca Knoll Gathering
system and the Poseidon Oil Pipeline system. Upon completion of this
transaction, EPG will become one of the largest gatherers of natural gas in the
onshore and offshore U.S. markets and will own interests in 47 pipeline systems,
25 natural gas processing and treating plants, and 8 offshore platforms.
 
     In December 1996, the Company completed its $4 billion acquisition of EPTPC
in a transaction accounted for as a purchase. The Merger was effected in
accordance with the Amended and Restated Agreement and Plan of Merger dated as
of June 19, 1996. In the Merger, Old Tenneco changed its name to EPTPC. Prior to
the Merger, Old Tenneco and its subsidiaries effected various intercompany
transfers and distributions which restructured, divided and separated their
businesses, assets and liabilities so that all the assets, liabilities and
operations related to their automotive parts, packaging and administrative
services businesses (collectively, the "Industrial Business") and their
shipbuilding business (the "Shipbuilding Business") were spun-off to Old
Tenneco's then existing common stockholders. Following the Distributions,
EPTPC's business consisted principally of the interstate transportation of
natural gas, as well as unregulated business operations such as gas marketing,
intrastate pipelines, international pipelines and power generation, and domestic
power generation. This acquisition created the nation's first coast-to-coast
natural gas pipeline system and continued the Company's effort to expand its
presence in non-regulated portions of the energy industry. As a result of the
Merger, EPG indirectly owns 100 percent of the common equity and approximately
75 percent of the combined equity value of EPTPC. The remaining 25 percent of
the combined equity of EPTPC is comprised of $300 million of preferred stock
issued in a public offering by Old Tenneco in November 1996, which remains
outstanding. For a further discussion of these acquisitions, see Note 2 of Item
8, Financial Statements and Supplementary Data.
 
                            NATURAL GAS TRANSMISSION
 
     The natural gas transmission segment is comprised of five interstate
pipeline systems: the TGP system, the EPG system, the Midwestern system, the
East Tennessee system, and the MPC system, collectively referred to as the
Interstate System. The Interstate System totals approximately 26,600 miles of
transmission pipeline. For information concerning the operating revenues,
operating income and identifiable assets attributable to this segment, see Note
12 of Item 8, Financial Statements and Supplementary Data.
 
     The TGP system. The TGP system consists of approximately 14,800 miles of
pipeline with a design capacity of 5,490 MMcf/d. During 1997, TGP transported
natural gas volumes averaging 87 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 Texas and Louisiana, including the Gulf of Mexico.
 
     The EPG system. The EPG system consists of approximately 9,900 miles of
pipeline with a design capacity of 4,744 MMcf/d. During 1997, EPG transported
natural gas volumes averaging approximately 72 percent of its capacity.
California is the single largest market served by the EPG system, which also
serves markets in Nevada, Arizona, New Mexico, Texas and northern Mexico. The
EPG system is connected to the San Juan Basin of northern New Mexico and
southern Colorado, and also accesses natural gas supplies in the Permian and
Anadarko Basins.
 
     The Midwestern system. The Midwestern system consists of approximately 400
miles of pipeline with a design capacity of 680 MMcf/d. During 1997, Midwestern
transported natural gas volumes averaging approximately 65 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 630 MMcf/d.
During 1997, East Tennessee transported natural gas volumes averaging
approximately 51 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.
 
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<PAGE>   7
 
     The MPC system. The MPC system consists of approximately 400 miles of
pipeline with a design capacity of approximately 400 MMcf/d. During 1997, MPC
transported natural gas volumes averaging approximately 74 percent of its
capacity. The MPC system is connected with the EPG system at Topock, Arizona and
extends to customers in the vicinity of Bakersfield, California.
 
     Other. The Company owns a 17.8 percent interest in the Portland Natural Gas
Transmission ("Portland") system which is developing a 292-mile interstate
natural gas pipeline with a projected capacity of 178 MMcf/d extending from the
Canadian border near Pittsburg, New Hampshire to Dracut, Massachusetts. Portland
received its FERC certificate in September 1997, and is now awaiting approval
from Canada's National Energy Board. Targeted completion is November 1998, at an
estimated total cost of $366 million.
 
     From time to time, the Company holds open seasons in an effort to
capitalize on pipeline expansion opportunities. Currently, TGP has announced the
Eastern Express Project 2000 which will provide gas transportation for the
growing markets in the northeast and mid-Atlantic regions of the United States.
TGP has also announced the Express 500 Expansion Project which is being designed
to meet the growing gas transportation demands in the Gulf of Mexico caused by
the significant increases in deepwater production. The projects are designed to
provide service to their markets beginning in the years 2000 and 1999,
respectively.
 
     In June 1997, EPG and its then partners in the TransColorado Pipeline
Project ("TransColorado") announced a restructured partnership arrangement
whereby affiliates of Questar Corporation and KN Energy, Inc., then one-third
partners along with an EPG affiliate, would become equal 50 percent partners in
TransColorado. EPG, while no longer a partner, will continue as the operator and
a revenue participant in the constructed facilities of Phase I which includes 25
miles of pipeline from the discharge of the Coyote Gulch natural gas treating
plant to EPG's pipeline at Blanco, New Mexico. EPG's revenue participation in
the project under the new arrangement will cease upon the completion of the
additional Phase II facilities which is expected to be in the fourth quarter of
1998.
 
  REGULATORY ENVIRONMENT
 
     The Interstate System is subject to the jurisdiction of FERC in accordance
with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978.
 
     Industry Restructuring. 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 themselves. 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.
 
     TGP. In December 1994, TGP filed for a general rate increase with FERC and
in April 1996, it filed a settlement resolving that proceeding. The settlement
included a structural rate design change that results in a
 
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larger portion of TGP's transportation revenues being dependent upon throughput.
In October 1996, FERC approved the stipulation with certain modifications and
clarifications which are not material. In January 1997, FERC issued an order
denying requests for rehearing of that order. One party, a competitor of TGP,
filed with the Court of Appeals a Petition for Review of the FERC orders.
 
     EPG. In June 1995, EPG filed with FERC for approval of new system rates for
mainline transportation to be effective January 1, 1996. In March 1996, EPG
filed a comprehensive offer of settlement to resolve that proceeding as well as
issues surrounding certain contract reductions and expirations that were to
occur from January 1, 1996 through December 31, 1997. In April 1997, FERC
approved EPG's settlement as filed and determined that only the contesting
party, Edison, should be severed for separate determination of the rate it
ultimately pays EPG. Hearings to determine Edison's rates are scheduled to begin
in April 1998. In July 1997, FERC issued an order denying the requests for
rehearing of the April 1997 order and the settlement was implemented effective
July 1, 1997. Edison and GPM Corporation, a competitor of EPG, have filed with
the Court of Appeals separate petitions for review of FERC's April 1997 and July
1997 orders.
 
     For a further discussion of regulatory matters related to TGP and EPG, see
Item 7, Management's Discussion and Analysis of Financial Condition and Results
of Operations and Note 5 of Item 8, Financial Statements and Supplementary Data.
 
  MARKETS AND COMPETITION
 
     The Interstate System faces varying degrees of competition from alternative
energy sources, such as electricity, hydroelectric power, coal, and oil. The
potential consequences of the proposed restructuring of the electric power
industry are currently unclear. It may benefit the natural gas industry by
creating more demand for 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 gas demand as a result of such restructuring.
 
     The TGP System. 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 revenues on TGP's
system. 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 three years,
principally in November 2000. TGP is actively pursuing the renegotiation,
extension and/or replacement of these contracts. 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.
 
     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 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 impacted by the foregoing competitive factors.
 
     The EPG System. EPG maintains a significant competitive position in the
California market by virtue of the fact that its pipeline is currently the
lowest-cost transporter of, and the principal means of moving, natural gas from
the San Juan Basin to the California border. EPG's current capacity to deliver
natural gas to California is approximately 3.3 Bcf/d, equivalent to
approximately 48 percent of the total interstate pipeline capacity serving that
state. Gas shipped to California across the EPG System represented approximately
34 percent of the natural gas consumed in the state in 1997. EPG customers
served in California during 1997 include SoCal with capacity of 1,150 MMcf/d
under contract until August 2006 and PG&E with capacity of 1,140 MMcf/d, whose
contract expired December 31, 1997.
 
     Interstate pipeline capacity utilization to California is currently
approximately 69 percent and is not expected to reach 100 percent until sometime
in the next decade, assuming no new interstate pipeline
 
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<PAGE>   9
 
construction. Currently, EPG has firm transportation contracts covering all of
its available capacity to California including those recently entered into with
NGC. As a part of its effort to remarket capacity relinquished by PG&E at the
end of 1997, EPG entered into three contracts with NGC for the sale of all of
its then available firm capacity for a two-year period beginning January 1, 1998
at rates pursuant to EPG's tariff provisions and FERC policies. For a further
discussion of capacity relinquishments, see Item 7, Management's Discussion and
Analysis of Financial Condition and Results of Operations.
 
     EPG faces significant competition from three other companies --
Transwestern, Kern River Gas Transmission Company and PG&E -- each of which
transports natural gas to the California market. The combined capacity of these
three companies and EPG for transporting natural gas to the California market is
approximately 6.9 Bcf/d. In 1997, the demand for interstate pipeline capacity to
California averaged 4.7 Bcf/d. Competition generally occurs on the basis of the
delivered cost of natural gas into the SoCal and PG&E distribution systems.
 
                          FIELD AND MERCHANT SERVICES
 
     The field and merchant services segment provides natural gas gathering,
products extraction, dehydration, purification, compression and intrastate
transmission services through EPFS. In addition, the segment markets and trades
natural gas, NGLs, power, crude and refined products, provides integrated price
risk management services associated with these commodities, and participates in
the development and ownership of domestic power generation projects through
EPEM. EPFS owns or has interests in approximately 8,750 miles of gathering
systems located in the country's most prolific and active gas production areas,
including the San Juan, Anadarko and Permian basins and in East Texas, South
Texas, Louisiana and the Gulf of Mexico. In addition, EPFS owns or has interests
in approximately 1,600 miles of intrastate transmission pipeline, which supply
natural gas to the Interstate System, and 25 natural gas processing and treating
facilities. For information concerning the operating revenues, operating income
and identifiable assets attributable to this segment, see Note 12 of Item 8,
Financial Statements and Supplementary Data.
 
  FIELD SERVICES
 
     EPFS, incorporated in June 1993, was formed for the purpose of owning,
operating, acquiring and constructing natural gas gathering, processing and
other related field facilities. Effective January 1, 1996, EPG transferred to
EPFS its non-regulated assets. These assets included major gathering systems in
the San Juan, Anadarko, and Permian Basins. From this initial asset base, EPFS
began to implement plans to increase gathering and processing volumes through a
strategy of project developments, acquisitions, and joint ventures.
 
     In March 1998, the Company and Deeptech entered into a definitive agreement
whereby the Company will acquire DeepTech as well as DeepTech's combined
ownership interest in Levianthan. Leviathan is a publicly traded partnership
that produces, processes, gathers, transports and markets oil and gas located in
the offshore Gulf of Mexico. In connection with the acquisition, the Company
will acquire the 15 percent minority equity interest in the holding company
through which DeepTech owns its Leviathan interests. After the transactions, the
Company will own 100 percent of the general partner of Leviathan and a 27.3
percent effective ownership interest in Leviathan.
 
     Major projects completed in 1997 include the following:
 
     - In December 1997, the Company acquired gathering facilities consisting of
       360 miles of pipeline and a cryogenic gas processing plant through the
       acquisition of 100 percent of the stock of PacifiCorp's Texas Gulf Coast
       gathering and processing subsidiaries.
 
     - In October 1997, the Company completed the acquisition of Gulf States Gas
       Pipeline Company. The assets purchased include a 175-mile gathering and
       intrastate transmission system in northwestern Louisiana with a capacity
       of 250 MMcf/d.
 
     - During the fourth quarter of 1997, Viosca Knoll Gathering Company, the
       Company's fifty-fifty joint venture with a subsidiary of Leviathan Gas
       Pipeline Partners, L.P., completed construction of
 
                                        5
<PAGE>   10
 
       additional facilities to accommodate incremental capacity requirements on
       its system, including a new 25-mile pipeline extending from Main Pass
       Block 261 to Viosca Knoll Block 817.
 
     Major projects completed in 1996 include the following:
 
     - The construction of the Coyote Gulch natural gas treating plant in La
       Plata County, Colorado was completed in the fourth quarter of 1996. The
       plant is a joint venture with KN Energy and has the capacity to treat 120
       MMcf/d. Initial treating began in December 1996.
 
     - The acquisition of the field services assets of EPTPC in December 1996,
       included approximately 200 miles of gathering and 1,300 miles of
       intrastate transportation systems and interests in seven natural gas
       processing plants. These assets are principally located in the Gulf Coast
       region of Texas.
 
     - The construction of the largest cryogenic liquids extraction plant in the
       continental U.S. was completed in 1996 (the "Chaco Plant"). Located in
       San Juan County, New Mexico, the Chaco Plant replaced a lean oil recovery
       plant previously operated by EPFS. The Chaco Plant can process up to 600
       MMcf/d and extract 50,000 barrels of NGLs per day.
 
     - The acquisition of Cornerstone was completed in June 1996. This
       acquisition added approximately 700 miles of gathering and transportation
       systems and seven liquids extraction and natural gas treating facilities.
       These assets are principally located in Louisiana and East Texas.
 
     The following table provides information as of December 31, 1997,
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 VOLUME GATHERED
                                   MILES      GATHERING/TRANSPORTATION           (BBTU/D)
                                    OF                CAPACITY           ------------------------
            SYSTEM              PIPELINE(1)         (MMCF/D)(2)           1997     1996     1995
            ------              -----------   ------------------------   ------   ------   ------
<S>                             <C>           <C>                        <C>      <C>      <C>
East Division.................     2,893                2,220              659      522      280
West Division.................     5,500                1,180            1,167    1,139    1,042
Gulf Coast Division...........     1,867                3,038              497       --       --
</TABLE>
 
------------
 
(1) Mileage amounts shown are approximate for the total system and have not been
    reduced to reflect EPFS's net ownership interest.
 
(2) All capacity information reflects EPFS's net ownership, which excludes
    entities accounted for under the equity method, and is subject to increases
    or decreases depending on operating pressures and point of delivery into or
    out of the system. The acquisitions of Gulf States Gas Pipeline Company in
    October 1997 and the gathering facilities of PacifiCorp's Texas Gulf Coast
    gathering subsidiaries in December 1997 increased capacity by 250 MMcf/d and
    1,430 MMcf/d for the East and Gulf Coast Divisions, respectively.
 
     The following table provides information concerning the processing
facilities at December 31, 1997:
 
<TABLE>
<CAPTION>
                                                                      AVERAGE    AVERAGE
                                                                       INLET       NGLS
                                                           INLET       VOLUME     SALES
                                                         CAPACITY     (BBTU/D)   (MGAL/D)
                        PLANT                           (MMCF/D)(1)     1997       1997
                        -----                           -----------   --------   --------
<S>                                                     <C>           <C>        <C>
East Division.........................................      300          164        300
West Division.........................................      600          551        505
Gulf Coast Division...................................      457          123        168
</TABLE>
 
------------
 
(1) All capacity information reflects EPFS's net ownership. The processing
    facilities acquired in December 1997 as part of PacifiCorp's Texas Gulf
    Coast operations increased capacity by 250 MMcf/d for the Gulf Coast
    Division.
 
                                        6
<PAGE>   11
 
     EPFS provides its customers with wellhead-to-mainline field services,
including natural gas gathering and transportation, products extraction,
dehydration, purification and compression. EPFS, together with EPEM, provides
fully bundled gas services with a broad range of pricing options as well as
financial risk management products. EPFS also provides well-ties and can offer
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.
 
  Competition
 
     EPFS operates in a highly competitive environment that includes independent
gathering and processing companies, intrastate pipeline companies, 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.
 
  MERCHANT SERVICES
 
     EPEM, the Company's merchant services business, markets and trades natural
gas, NGLs, power, crude and refined products, and participates in the
development and ownership of domestic power generation projects. EPEM has
emerged as one of North America's largest energy marketing and trading
companies. In the fourth quarter of 1997, EPEM marketed physical and financial
gas volumes of over 9,500 BBtu/d.
 
     EPEM provides a broad range of energy products and services, including
supply aggregation, transportation management, and integrated price risk
management. EPEM maintains a diverse natural gas supplier and customer base
serving producers, utilities (including local distribution companies and power
plants), municipalities, and a variety of industrial and commercial end users.
In 1997, EPEM served over 400 producers/suppliers and approximately 2,000 sales
customers in 26 states with transportation of gas supplies on 65 pipelines.
 
     Set forth below are the average daily marketed physical and financial gas,
power and NGLs volumes for the years ended December 31:
 
<TABLE>
<CAPTION>
                                                            1997      1996(1)    1995
                                                           -------    -------    -----
<S>                                                        <C>        <C>        <C>
Marketed Gas Volumes (BBtu)..............................    6,969      6,320     772
Marketed Power (thousand MWH)............................   12,969      3,878      --
Marketed NGLs (net gallons in thousands).................  230,202    322,591      --
</TABLE>
 
(1) Average daily volumes for the energy marketing activities of EPTPC, acquired
    in December 1996, are reflected from the date of acquisition in 1996 and for
    the full year of 1997.
 
     Demand for natural gas products and services has primarily resulted from
the effects of FERC Order No. 636, the commercialization of natural gas, and the
intense competition within the industry. Volatility in the physical and
financial gas markets has compounded the effects of these changes creating
greater service opportunities.
 
     In the course of its business, EPEM trades and develops a market in natural
gas in both the physical and financial markets, and purchases or sells swaps and
options in the OTC financial markets with major energy merchants. EPEM seeks to
maintain a balanced portfolio of supply and demand contracts and utilizes the
New York Mercantile Exchange and OTC financial markets to manage price and basis
risk which may affect those obligations. To support these activities, EPEM
employs centralized corporate risk management and trading strategies. For
additional information regarding the use of financial instruments, see Item 7A,
Quantitative and Qualitative Disclosures About Market Risk and Note 4 of Item 8,
Financial Statements and Supplementary Data.
 
     In 1996, EPEM formed a power marketing group to capitalize on the
opportunities created by the deregulation of the electric industry, which
participates in wholesale power trading and offers products and
 
                                        7
<PAGE>   12
 
services to industrial and commercial end users of electricity. During 1997, the
power marketing group sold 12,969,000 MW hours of electricity, ranking it among
the top 25 power marketers in the country. In its continued efforts to expand
its power marketing and merchant activities, EPEM formed El Paso Power Services
in February 1998. El Paso Power Services will focus on helping electric
utilities, non-utility and merchant generators, fuel suppliers, and large
industrial concerns achieve lower costs in the transition to a competitive
marketplace.
 
     The Company entered into a development agreement with Power Development
Company to jointly develop a natural gas-fired combined cycle electric
generation facility in Agawam, Massachusetts. The facility will have a normal
capacity of approximately 270 MWs. In December 1997, the entity that will own
and operate the plant completed non-recourse project financing which includes a
$50 million equity bridge loan and a 24-month $150 million construction loan. At
completion of construction, the Company will make its equity contribution of up
to $50 million, representing a 90 percent equity interest in the joint venture,
and the construction loan will convert to a 17-year $150 million term loan.
Construction of the facility began in December 1997 and it is scheduled to
commence operations in December 1999. EPEM will be responsible for the
procurement and transportation of supplies of natural gas to fuel the project
and the marketing of the electric power that the plant produces. EPEM is also
pursuing the development of other domestic power generating facilities.
 
  Competition
 
     EPEM operates in a highly competitive environment where 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, imbalance management, and
experience in the marketplace.
 
                              CORPORATE AND OTHER
 
     The Company's corporate and other segment includes its international
development activities, as well as certain other corporate activities. The
international development activities are conducted principally through EPEI and
the international activities of EPTPC (acquired in December 1996). For
information concerning the operating revenues, operating income and identifiable
assets attributable to this segment, see Note 12 of Item 8, Financial Statements
and Supplementary Data.
 
  INTERNATIONAL AND OTHER ENERGY-RELATED BUSINESS
 
     EPEI was incorporated in June 1995 for the purpose of investing in energy
projects with an emphasis on developing infrastructure to gather, transport and
use natural gas in northern Mexico and certain
Latin America countries. With the combination of EPTPC's international
activities, the focus of international project pursuit has expanded to encompass
Australia, Asia, Europe and other Latin American countries. Set forth below are
brief descriptions of the projects that are either operational or are in various
stages of development by major region of focus.
 
     Acquisitions and greenfield development projects are subject to a higher
level of commercial and financial risk in foreign countries. Accordingly the
Company has adopted a risk mitigation plan to reduce the risk to more acceptable
and manageable levels. The Company's practice is to select experienced partners
with a history of success in commercial operations. Selected partners will
generally be chosen based on the complementary competencies which they offer to
the various joint ventures formed or to be formed. The Company designs and
implements a formal due diligence plan on every project it pursues and contracts
are negotiated to secure fuel source, manage operation and maintenance costs
and, when possible, index revenues to the U.S. dollar. The Company will obtain
political risk insurance when deemed appropriate, through the Overseas Private
Investment Corporation, the Multilateral Investment Guarantee Agency, or some
other private insurer.
 
                                        8
<PAGE>   13
 
Latin America and Mexico
 
     Samalayuca Power Project -- The Company has a 30 percent interest in a
consortium that is
constructing a 700 MW combined cycle gas fired power plant in Samalayuca,
Mexico. The first unit of the plant is scheduled to be operational by May of
1998. The second and third units are scheduled to be operational by December of
1998. CFE will operate 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 will deliver natural gas to the
Samalayuca Power Project from EPG'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 EPG) and 23 miles of pipeline in Mexico
(currently 50 percent owned by the Company).
 
     Aguaytia Project -- The Company has a 23 percent interest in a consortium
that is developing an integrated gas and power project near Pucallpa, located in
central Peru. The project consists of the development of a 300 Bcf natural gas
reserve, a gas processing facility, a 71-mile gas liquids pipeline to a
fractionation facility, a 126-mile pipeline to a 155 MW simple cycle power
plant, and a 250-mile transmission line that will interconnect with the Peruvian
grid at Paramonga. The project is expected to begin operations in early 1998.
 
     CAPSA -- In March 1997, the Company purchased an effective 29 percent
interest in CAPSA, a privately held integrated energy company in Argentina. The
Company has exercised its option to acquire an additional 16 percent interest in
CAPSA bringing its total ownership to 45 percent as of January 1998. 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 that owns the 382 MW Agua del Cajon gas fired power plant in
western Argentina. This plant has been fully operational since 1995 and buys 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 has a 10 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 natural gas pipeline. The 325-mile
pipeline will cross the Andes Mountains connecting natural gas production in
Argentina's Neuquen Basin to customers in Concepcion, Chile. Construction of the
pipeline is scheduled to commence in early 1998 with an expected in service date
of late 1999.
 
     Manaus Power Project -- In 1997, the Company began construction of a 250 MW
power plant in Manaus, the capital city of the state of Amazonas in northern
Brazil. The project will supply electric power to the city of Manaus under a
four year contract. The project is being built in three phases. The first phase
is a 44 MW unit that commenced operations at approximately 22 MW in February
1998. Substantially all of the remaining capacity for the first phase and the
other two phases of the project is planned to be operational in the first
quarter of 1998 and will bring total capacity to 250 MW. The contract for the
project provides for delay damages to be paid to the power purchaser in the
event of a failure to meet the specified construction schedule, except for
delays caused by events of force majeure. The completion of the project has been
delayed beyond the dates provided in the contract and such delays could give
rise to a claim for delay damages from the power purchaser. The Company has a
right to assert claims against the construction contractor for such delay
damages, and in any event does not believe that any such claim will have a
material adverse affect on the Company. Initially, the plant will be simple
cycle turbine generators powered by fuel oil. However, the Company is evaluating
a conversion to a natural gas fired combined cycle plant within the next few
years. In September 1997, the Company sold 50 percent of its interest in this
project to CAPEX. The Company plans to finance the project on a non-recourse
basis during the second quarter of 1998.
 
     Mato Grosso do Sul Power Project -- In July 1997, the Company was awarded
the contract to build, own and operate a 150 MW power plant in the state of Mato
Grosso do Sul in southwestern Brazil. The facility, to
 
                                        9
<PAGE>   14
 
be located in Corumba, will be the first independent power project fueled by
natural gas in the region. Construction on the Mato Grosso do Sul power plant
will begin in early 1998 and be built in two phases. The first phase will
provide 75 MW in simple cycle approximately one year after signing the power
purchase agreement with Eletrosul, a subsidiary of the Brazilian utility
Eletrobras. The Company is currently negotiating the power purchase agreement
with Electrobras. The second phase of the project will provide an additional 75
MW in combined cycle and is expected to be operational by July 1999.
 
     Macae Power Project -- The Company has approximately a 30 percent interest
in a consortium to build a 450 MW gas fired power plant in the northern part of
the state of Rio de Janeiro, in southeastern Brazil. The thermal power plant,
located in the region of Macae, is one of the first to be fueled by natural gas
in the country and will include construction of a 22-mile transmission line
which will tie into Brazil's Interconnected Electric System. Construction is
expected to commence in 1998, with initial operations in 1999 and full
commercial operations in the year 2000.
 
     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 by
the first quarter of 1999. The Company's interest in the project will be
approximately 10 percent.
 
     Parana Power Project -- The Company has approximately a 20 percent interest
in a consortium to build a 440 MW natural gas fired thermoelectric power plant
in the state of Parana, in southern Brazil. The thermal power plant, to be
located in Araucaria, will be built in two phases. The first phase will provide
300 MW of power and is expected to be in service by 1999. The 140 MW second
phase is scheduled to be operational in the year 2000. 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. Construction is expected to begin during
1998 and completion of the first phase is expected to coincide with the startup
of the Bolivia to Brazil pipeline project.
 
Europe
 
     EMA Power -- In June 1997, the Company purchased a 50 percent controlling
interest in an operating 70 MW power plant located in Danaujvaros, Hungary. The
electricity generated at the plant is consumed by Dunafer Kft., the largest
steel mill in Hungary. The acquisition agreement requires the Company to
evaluate and, if deemed economically feasible, to expand the electric generating
plant to 140 MW. The feasibility study is underway.
 
     Kladno Power -- In June 1997, the Company acquired a 31 percent interest in
a 322 MW natural gas and coal fired expansion and upgrade of an existing 28 MW
cogeneration facility approximately 19 miles northwest of Prague, the Czech
Republic. Non-recourse project financing was finalized in June 1997. In the
first quarter of 1998, the Company signed an agreement with NRG Energy, one of
the partners in the project, to acquire an additional 13 percent interest in the
project in early 1998.
 
Asia Pacific
 
     Australian Pipelines -- The Company owns a 30 percent interest in the
Moomba to Adelaide transmission system, a 483-mile natural gas pipeline in
southern Australia and the Ballera to Wallumbilla transmission system, a
470-mile natural gas pipeline in southwestern Queensland. Both pipelines were
operational in 1997. The Company's joint venture has been selected to construct
the 270 mile expansion project on the Dampier-to-Bunburry natural gas pipeline
in western Australia. The expansion project is expected to commence operations
in the third quarter of 1999.
 
     On March 3, 1998 the Company announced that Epic Energy (WA) Pipeline Trust
venture, in which a subsidiary of the Company owns a 33.3 percent interest, has
been awarded the right to purchase the 925-mile Dampier-to-Bunbury natural gas
pipeline in western Australia. The Dampier-to-Bunbury pipeline is a 550 MMcf/d
pipeline system that serves a number of western Australian markets, including
industrial
                                       10
<PAGE>   15
 
end-users. An expansion of the Dampier-to-Bunbury natural gas pipeline is
currently underway to supply natural gas to expansions committed by Alcoa,
Worsley and Wesfarmers.
 
     Sengkang Project -- The Company has a 50 percent interest in a producing
500 Bcf gas field and a 47.5 percent interest in a 135 MW power generating plant
in Sengkang, South Sulawesi, Indonesia. The electricity produced by the power
plant is sold to PLN, the national electric utility, pursuant to 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 is expected in the third
quarter of 1998. For a discussion on the devaluation of the Indonesian Rupiah,
see Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations.
 
     Kabirwala Power -- In February 1997, the Company acquired a 42 percent
interest in a 151 MW gas fired power plant currently under construction in
Kabirwala, Pakistan. Simple cycle operation is planned for November 1998 with
combined cycle operations in November 1999. The power plant will sell
electricity to the state Water and Power Development Authority.
 
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 capacity of 220 MW of power
generation.
 
                                     OTHER
 
     As a result of the Merger, the Company holds certain limited assets and is
responsible for certain liabilities of EPTPC's existing and discontinued
operations and businesses. The liabilities were approximately $600 million at
the time of the Merger. In addition, the Company, through its corporate and
other segment, performs management, legal, financial, tax, consultative,
administrative and other services for the business segments of the Company.
 
                                 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, 1997, the Company had a reserve of
approximately $284 million for the following environmental contingencies which
the Company anticipates incurring through 2027: (i) expected remediation costs
and associated onsite, offsite and groundwater technical studies of
approximately $257 million; and (ii) other costs of approximately $27 million.
For a further discussion of specific environmental matters, see Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations; Item 3, Legal Proceedings; and Note 5 of Item 8, Financial
Statements and Supplementary Data.
 
                                   EMPLOYEES
 
     The Company had approximately 3,500 full-time employees on December 31,
1997. The Company has no collective bargaining arrangements. Since December 31,
1996, the Company has reduced its workforce by approximately 800 employees as a
result of a program to streamline operations and reduce operating costs. No
significant changes in the workforce have occurred since December 31, 1997.
 
                                       11
<PAGE>   16
 
                      EXECUTIVE OFFICERS OF THE REGISTRANT
 
     The executive officers of EPG as of March 16, 1998, were as follows:
 
<TABLE>
<CAPTION>
                                                                             OFFICER
            NAME                                  OFFICE                      SINCE     AGE
            ----                                  ------                     -------    ---
<S>                            <C>                                           <C>        <C>
William A. Wise..............  Chairman of the Board and Chief Executive      1983      52
                                 Officer of EPG
Richard Owen Baish...........  President of EPG                               1987      51
H. Brent Austin..............  Executive Vice President and Chief Financial   1992      43
                                 Officer of EPG
Joel Richards III............  Executive Vice President of EPG                1990      51
Britton White, Jr............  Executive Vice President and General Counsel   1991      54
                                 of EPG
John D. Hushon...............  President, EPEI                                1996      52
Greg G. Jenkins..............  President, EPEM                                1996      40
Robert G. Phillips...........  President, EPFS                                1995      43
Mark A. Searles..............  Executive Vice President, EPEM                 1995      41
John W. Somerhalder II.......  President, TGP                                 1990      42
</TABLE>
 
     Mr. Wise has been Chairman of the Board of EPG since January 1994 and Chief
Executive Officer since January 1990. He was President of EPG from April 1989 to
April 1996. From March 1987 until April 1989, Mr. Wise was an Executive Vice
President of EPG. From January 1984 to February 1987, he was a Senior Vice
President of EPG. Mr. Wise is a member of the Board of Directors of Battle
Mountain Gold Company.
 
     Mr. Baish has been President of EPG since April 1996. From September 1994
until April 1996, he was Executive Vice President of EPG and was Senior Vice
President from November 1990 to August 1994. He was General Counsel and
Corporate Secretary from November 1990 to December 1990 and Vice President and
Associate General Counsel from March 1987 to October 1990.
 
     Mr. Austin has been Executive Vice President of EPG since May 1995. He has
been Chief Financial Officer of EPG since April 1992. He was Senior Vice
President of EPG from April 1992 to April 1995. He was Vice President, Planning
and Treasurer of 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 EPG since December 1996.
From January 1991 until December 1996, he was Senior Vice President of EPG. 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 of EPG since December 1996 and
General Counsel of EPG since March 1991. He was Senior Vice President and
General Counsel of EPG from March 1991 until December 1996. From March 1991 to
April 1992, he was also Corporate Secretary of EPG. For more than five years
prior to that time, Mr. White was a partner in the law firm of Holland & Hart.
 
     Mr. Hushon has been President of EPEI since April 1996. He was Senior Vice
President of EPEI from September 1995 to April 1996. For more than five years
prior to that time, Mr. Hushon was a senior partner in the law firm of Arent Fox
Kintner Plotkin & Kahn.
 
     Mr. Jenkins has been President of EPEM since December 1996. He was Senior
Vice President and General Manager of Entergy Corp. from May 1996 to December
1996 and President and Chief Executive Officer of Hadson Gas Services Company
from December 1993 to January 1996. For more than five years prior to that time,
Mr. Jenkins was in various managerial positions with Santa Fe Energy Resources,
Inc.
 
     Mr. Searles has been Executive Vice President of EPEM since June 1997. He
was President of EPFS from December 1996 to June 1997 and was President of EPEM
from September 1995 to December 1996.
 
                                       12
<PAGE>   17
 
From March 1994 to September 1995, Mr. Searles was President and Chief Operating
Officer of Eastex Energy, Inc. For more than five years prior to that he held
various management positions with Enron Corp.
 
     Mr. Phillips has been President of EPFS since June 1997. He was President
of El Paso Energy Resources Company from December 1996 to June 1997, President
of EPFS from April 1996 to December 1996 and was a Senior Vice President of EPG
from September 1995 to April 1996. For more than five years prior to that time,
Mr. Phillips was Chief Executive Officer of Eastex Energy Inc.
 
     Mr. Somerhalder has been President of TGP since December 1996. He was
President of El Paso Energy Resources Company from April 1996 to December 1996
and Senior Vice President of EPG from August 1992 to April 1996. From January
1990 to July 1992, he was Vice President of EPG.
 
     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. In
addition the Company's physical properties are adequate and suitable for the
conduct of its business in the future.
 
ITEM 3. LEGAL PROCEEDINGS
 
     In November 1993, TransAmerican filed a complaint in a Texas state court,
TransAmerican Natural Gas Corporation v. El Paso Natural Gas Company, et al,
alleging fraud, tortious interference with contractual relationships, negligent
misrepresentation, economic duress, civil conspiracy, and violation of state
antitrust laws arising from a settlement agreement entered into by EPG,
TransAmerican, and others in 1990 to settle litigation then pending and other
potential claims. The complaint, as amended, seeks unspecified actual and
exemplary damages. EPG is defending the matter in the State District Court of
Dallas County, Texas. In April 1996, a former employee of TransAmerican filed a
related case in Harris County, Texas, Vickroy E. Stone v. Godwin & Carlton,
P.C., et al. (including EPG), seeking indemnification and other damages in
unspecified amounts relating to litigation consulting work allegedly performed
for various entities, including EPG, in cases involving TransAmerican. EPG filed
a Motion for Summary Judgment in the TransAmerican case arguing that plaintiff's
claims are barred by a prior release executed by TransAmerican, by statutes of
limitations, and by the final court judgment in EPG's favor ending the original
litigation in 1990. Following a hearing in January 1998, the court granted
summary judgment on TransAmerican's claims based on economic duress and
negligent misrepresentation, but denied the motion as to the remaining claims.
In February, EPG filed a Motion for Summary Judgment in the Stone litigation
arguing that all claims are baseless, barred by statutes of limitations, subject
to executed releases, or have been assigned to TransAmerican; oral argument on
the motion was set in March 1998 and a decision is pending. The trials in
TransAmerican and Stone are set to commence in March 1999 and September 1998,
respectively. Based on information available at this time, management believes
that the claims asserted against it in both cases have no factual or legal basis
and that the ultimate resolution of these matters will not have a material
adverse effect on the Company's financial position or results of operations.
 
     On February 12, 1998, the United States and the State of Texas filed in a
United States District Court a Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA) cost recovery action, United States v.
Atlantic Richfield Co., et al, against fourteen companies including TGP, EPTPC,
EPEC Corp., EPEC Polymers, Inc. and the recently dissolved Petro-Tex Chemical
Corp., 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
Corp. arranged for disposal of hazardous substances at Sikes. TGP, EPTP, EPEC
Corp. 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
 
                                       13
<PAGE>   18
 
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. Although
factual investigation relating to Sikes is in very preliminary stages, the
Company believes that the amount of material disposed at Sikes from the Tenneco
Chemicals, Inc. or Petro-Tex Chemical Corp. facilities, if any, 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 or results of
operations.
 
     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 or results of operations.
 
     In Commonwealth of Kentucky, Natural Resources and Environmental Protection
Cabinet v. Tennessee Gas Pipeline Company (Franklin County Circuit Court, Docket
No. 88-C1-1531, November 16, 1988), the Kentucky environmental agency alleged
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 its Kentucky 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 or results of
operations.
 
     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 or
results of operations.
 
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
 
     None
 
                                       14
<PAGE>   19
 
                                    PART II
 
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
 
     EPG's common stock is traded on the New York Stock Exchange. As of March
16, 1998, the number of holders of record of common stock was approximately
73,000. This does not include individual participants on whose behalf a clearing
agency, or its nominee, holds EPG's common stock.
 
     The following table reflects the high and low sales prices for EPG's common
stock for the periods indicated based on the daily composite listing of stock
transactions for the New York Stock Exchange and cash dividends declared during
those periods.
 
<TABLE>
<CAPTION>
                                                           HIGH       LOW      DIVIDENDS
                                                         --------   --------   ---------
                                                                   (PER SHARE)
<S>                                                      <C>        <C>        <C>
1997
  First Quarter........................................  $57.0000   $48.8750    $0.3650
  Second Quarter.......................................  $60.6250   $54.2500    $0.3650
  Third Quarter........................................  $60.6875   $53.0000    $0.3650
  Fourth Quarter.......................................  $67.5000   $55.3750    $0.3650
1996
  First Quarter........................................  $38.1250   $28.6250    $0.3475
  Second Quarter.......................................  $39.0000   $34.2500    $0.3475
  Third Quarter........................................  $45.8750   $37.7500    $0.3475
  Fourth Quarter.......................................  $53.2500   $44.0000    $0.3475
</TABLE>
 
     In January 1998, the Board declared a quarterly dividend of $0.3825 per
share on EPG's common stock, payable on April 1, 1998, to stockholders of record
on March 6, 1998. The declaration of future dividends will be dependent upon
business conditions, earnings, the cash requirements of EPG, and other relevant
factors.
 
     Also, in January 1998, the Board declared a two-for-one stock split in the
form of a 100 percent stock dividend (on a per share basis). In March 1998, the
stockholders approved an increase in the Company's authorized common stock. The
proposed stock dividend will be paid on April 1, 1998 to stockholders of record
on March 13, 1998. All presentations herein are made on a pre-split basis.
Separately, the Board also approved a new 5 million common stock repurchase
authority that will replace the repurchase authority approved by the Board in
November 1994. The timing and amount of share repurchases, if any, will depend
upon the availability and alternate uses of capital, market conditions and other
factors. The share repurchase authority will increase to 10 million shares after
the two-for-one stock split has been effectuated.
 
     In February 1997, the Company sold approximately 3 million shares of its
common stock in a public offering for a price per share of $52.50. Aggregate
proceeds of $152 million were received, net of issuance costs.
 
     EPG has made available the Program, in which Odd-Lot Holders are offered a
convenient method of disposing of all their shares without incurring any
brokerage costs associated with the sale of an odd-lot. Only Odd-Lot Holders are
eligible to participate in the Program. The Program is strictly voluntary, and
no Odd-Lot Holder is obligated to sell pursuant to the Program. A brochure and
related materials describing the Program were sent to Odd-Lot Holders in
February 1994. The Program currently does not have a termination date, but EPG
may suspend the Program at any time. Inquiries regarding the Program should be
directed to Boston EquiServe.
 
     EPG has made available the Plan, which provides all stockholders of record
a convenient and economical means of increasing their holdings in EPG's common
stock. A stockholder who owns shares of common stock in street name or broker
name and who wishes to participate in the Plan will need to have his or her
broker or nominee transfer the shares into the stockholder's name. The Plan is
strictly voluntary, and no stockholder of record is obligated to participate in
the Plan. A brochure and related materials describing the Plan were sent to
 
                                       15
<PAGE>   20
 
stockholders of record in November 1994. The Plan currently does not have a
termination date, but EPG may suspend the Plan at any time. Inquiries regarding
the Plan should be directed to Boston EquiServe.
 
ITEM 6. SELECTED FINANCIAL DATA
 
<TABLE>
<CAPTION>
                                                                     YEAR ENDED DECEMBER 31,
                                                        -------------------------------------------------
                                                         1997     1996(a)    1995(a)     1994      1993
                                                        -------   --------   --------   -------   -------
                                                         (IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<S>                                                     <C>       <C>        <C>        <C>       <C>
Operating Results Data:
  Operating revenues..................................  $5,638     $3,012     $1,038    $  870    $  909
  Employee separation and asset impairment
     charge(b)........................................      --         99         --        --        --
  Net income..........................................     186         38         85        90        92
  Basic earnings per common share(b)..................    3.27       1.06       2.47      2.45      2.46
  Diluted earnings per common share...................    3.18       1.04       2.47      2.45      2.46
  Cash dividends declared per common share............    1.46       1.39       1.32      1.21      1.10
  Basic average common shares outstanding.............      57         36         34        37        37
  Diluted average common shares outstanding...........      59         37         34        37        37
</TABLE>
 
<TABLE>
<CAPTION>
                                                                        DECEMBER 31,
                                                        --------------------------------------------
                                                         1997    1996(a)   1995(a)    1994     1993
                                                        ------   -------   -------   ------   ------
                                                                       (IN MILLIONS)
<S>                                                     <C>      <C>       <C>       <C>      <C>
Financial Position Data:
  Total assets........................................  $9,532   $8,843    $2,535    $2,332   $2,270
  Long-term debt......................................   2,119    2,215       772       779      796
  Preferred stock of subsidiary.......................     300      296        --        --       --
  Other minority interest.............................      65       39        --        --       --
  Stockholders' equity................................   1,959    1,638       712       710      708
</TABLE>
 
---------------
 
(a) Reflects the acquisition in September 1995 of Eastex Energy Inc., in
    December 1995 of Premier, in
    June 1996 of Cornerstone, and in December 1996 of EPTPC. All acquisitions
    were accounted for as a purchase and therefore operating results are
    included prospectively from the date of acquisition.
 
(b) Reflects a charge of $99 million pre-tax ($60 million after tax) to reflect
    costs associated with the implementation of a workforce reduction plan and
    the impairment of certain long-lived assets. Basic earnings per common share
    for the year ended December 31, 1996 before giving effect to this charge and
    an $8 million pre-tax ($5 million after tax) charge taken in the fourth
    quarter for relocating the corporate headquarters from El Paso, Texas to
    Houston, Texas in connection with the acquisition of EPTPC, would have been
    $2.85 (compared to $1.06).
 
                                       16
<PAGE>   21
 
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS
 
                                    GENERAL
 
     Beginning in late 1995, and continuing through 1996 and 1997, the Company
was engaged in numerous activities and transactions designed to significantly
improve its ability to compete effectively in the rapidly evolving world energy
industry. In late 1995, the Company acquired two energy marketing businesses,
Eastex Energy Inc. and Premier. During the first quarter of 1996, the Company
completed its organizational review and workforce reduction program, reducing
the total workforce from 2,400 to about 1,600. During May 1996, the Company
completed and placed in service the Chaco Plant, the largest facility of its
kind in the continental U.S. In June 1996, the Company acquired Cornerstone,
expanding its gathering and processing operations into Louisiana and East Texas.
The Company completed its $4 billion acquisition of EPTPC in December 1996,
expanding its natural gas pipeline systems from coast to coast and continuing
the expansion of the non-regulated business operations. In connection with the
EPTPC acquisition, the Company completed a workforce reduction program in the
first quarter of 1997, reducing the workforce of the combined companies by
approximately 800 from about 4,300 following the acquisition of EPTPC to about
3,500. In late 1997, the Company acquired additional gathering and processing
assets by completing the purchases of Gulf States Gas Pipeline Company and
certain Texas Gulf Coast subsidiaries of PacifiCorp. Additionally, throughout
1996 and 1997, the Company's international operations were expanding into Latin
American, Asia Pacific and Europe.
 
     These changes in the make-up of the Company significantly increased the
Company's operating results, its ability to generate operating cash flows and
its needs for cash for investment opportunities. Consequently, the Company's
credit facilities were substantially expanded during this period to meet these
needs.
 
     In response to these changes in the energy industry and the manner in which
the Company manages its businesses, the Company restructured its business
activities into three segments: (i) natural gas transmission, (ii) field and
merchant services, and (iii) corporate and other, which includes the Company's
international project development activities. The changes in operating results
from period to period and changes in the Company's liquidity and capital
resources (each explained below) are substantial, especially between 1997 and
1996, due to the activities and transactions discussed above. To the extent
practicable, results of operations for 1995 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 the period.
 
                             RESULTS OF OPERATIONS
 
YEAR ENDED DECEMBER 31, 1997, COMPARED TO YEAR ENDED DECEMBER 31, 1996
 
  NATURAL GAS TRANSMISSION
 
<TABLE>
<CAPTION>
                                                                YEAR ENDED
                                                               DECEMBER 31,
                                                              --------------
                                                               1997     1996
                                                              ------    ----
                                                              (IN MILLIONS)
<S>                                                           <C>       <C>
Transportation revenue......................................  $1,227    $537
Other revenue...............................................      92      21
                                                              ------    ----
  Operating revenue.........................................   1,319     558
Operating expenses..........................................     759     335
                                                              ------    ----
  Operating income..........................................  $  560    $223
                                                              ======    ====
</TABLE>
 
     Operating revenue for the year ended December 31, 1997, was $761 million
higher than for the same period of 1996 primarily due to the acquisition of
EPTPC.
 
     Operating expenses for the year ended December 31, 1997, were $424 million
higher than for the same period of 1996 primarily due to the acquisition of
EPTPC. This increase in operating expenses was partially
 
                                       17
<PAGE>   22
 
offset by lower labor costs, benefit costs, and payroll taxes in 1997 which
resulted from a reduction in staffing levels during 1996.
 
  FIELD AND MERCHANT SERVICES
 
<TABLE>
<CAPTION>
                                                                YEAR ENDED
                                                               DECEMBER 31,
                                                              --------------
                                                              1997     1996
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Gathering and treating margin...............................  $123     $ 79
Processing margin...........................................    55       53
Marketing margin............................................    17       47
Other margin................................................     6        1
                                                              ----     ----
  Total gross margin........................................   201      180
Operating expenses..........................................   167      123
                                                              ----     ----
  Operating income..........................................  $ 34     $ 57
                                                              ====     ====
</TABLE>
 
     Total gross margin for the year ended December 31, 1997, was $21 million
higher than for the same period of 1996. The increases experienced in the
gathering and treating margin and the processing margin were primarily the
result of higher natural gas prices in the San Juan Basin, slightly higher NGL
prices, an increase in gathering and treating volumes due to the acquisitions of
Cornerstone and EPTPC, and an increase in NGLs attributable to the Chaco Plant,
which began processing in the second quarter of 1996. Partially offsetting the
increase in total gross margin was a decrease in the marketing margin resulting
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.
 
     Operating expenses for the year ended December 31, 1997, were $44 million
higher than for the same period of 1996 primarily due to the acquisitions of
Cornerstone in June 1996, and EPTPC in December 1996.
 
  CORPORATE AND OTHER
 
<TABLE>
<CAPTION>
                                                               YEAR ENDED
                                                              DECEMBER 31,
                                                              -------------
                                                              1997    1996
                                                              ----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Operating revenue...........................................  $ 19    $   1
Operating expenses..........................................    92      111
                                                              ----    -----
  Operating income (loss)...................................  $(73)   $(110)
                                                              ====    =====
</TABLE>
 
     The operating loss for the year ended December 31, 1997, was $37 million
less than for the same period of 1996. The decrease was primarily the result of
two charges recorded in 1996 that did not recur in 1997 consisting of a $99
million employee separation and asset impairment charge recorded in March 1996
and an $8 million charge in the fourth quarter of 1996 for relocating the
Company's headquarters from El Paso, Texas to Houston, Texas in connection with
the acquisition of EPTPC. The decrease was largely offset by additional costs
related to the discontinued operations assumed as part of the EPTPC acquisition,
development costs related to the Company's expanding international operations,
severance and relocation costs, and the cost of certain employee equity
incentive plans.
 
                                       18
<PAGE>   23
 
YEAR ENDED DECEMBER 31, 1996, COMPARED TO YEAR ENDED DECEMBER 31, 1995
 
  NATURAL GAS TRANSMISSION
 
<TABLE>
<CAPTION>
                                                                YEAR ENDED
                                                               DECEMBER 31,
                                                               -------------
                                                               1996     1995
                                                               ----     ----
                                                               (IN MILLIONS)
<S>                                                            <C>      <C>
Transportation revenue......................................   $537     $512
Other revenue...............................................     21       28
                                                               ----     ----
  Operating revenue.........................................    558      540
Operating expenses..........................................    335      337
                                                               ----     ----
  Operating income..........................................   $223     $203
                                                               ====     ====
</TABLE>
 
     Operating revenue for the year ended December 31, 1996, was $18 million
higher than for the same period of 1995 primarily due to the December 1996,
acquisition of EPTPC. This increase was partially offset by an accrual for
regulatory issues and a decrease in take or pay cost recoveries.
 
     Operating expenses for the year ended December 31, 1996, were $2 million
lower than for the same period of 1995 primarily due to lower operation and
maintenance expenses resulting primarily from the Company's program to reduce
operating costs which was adopted in the first quarter of 1996. For a further
discussion of operating cost reductions, see Note 10 of Item 8, Financial
Statements and Supplementary Data.
 
  FIELD AND MERCHANT SERVICES
 
<TABLE>
<CAPTION>
                                                                YEAR ENDED
                                                               DECEMBER 31,
                                                               -------------
                                                               1996     1995
                                                               ----     ----
                                                               (IN MILLIONS)
<S>                                                            <C>      <C>
Gathering and treating margin...............................   $ 79     $ 81
Processing margin...........................................     53       13
Marketing margin............................................     47       --
Other margin................................................      1       --
                                                               ----     ----
  Total gross margin........................................    180       94
Operating expenses..........................................    123       93
                                                               ----     ----
  Operating income..........................................   $ 57     $  1
                                                               ====     ====
</TABLE>
 
     Gross margin and operating income for 1996 increased $86 million and $56
million, respectively. This was primarily a result of increased margins and
earnings from the gas processing and gas marketing businesses. The 1996 increase
in marketing margin reflects the results of Eastex Energy Inc. (now EPEM) for
the entire year. The increase in processing margin was primarily caused by the
startup of operations at the Chaco Plant and the acquisition of Cornerstone. The
Chaco Plant began processing in May 1996 and was fully operational in September
1996. The Chaco Plant processed an average of 570 Mdth/d in the fourth quarter
and experienced recoveries of over 90 percent for ethane and 99 percent for
propane and heavier NGLs. The Cornerstone gas processing facilities were
acquired in June 1996 and processed an average of 160 Mdth/d through the
remainder of 1996.
 
     The gathering and processing operations benefited from an increase in both
natural gas and NGLs prices, particularly in the fourth quarter of 1996. Many of
the EPFS contracts are based on a percentage of products extracted or have fees
based on the price of natural gas. Product prices in the fourth quarter of 1996
were near historic highs and had a significant impact on earnings.
 
     The increase in operating expenses for 1996 was due primarily to the
acquisition of Cornerstone in June 1996 and Eastex Energy Inc. in September
1995.
 
                                       19
<PAGE>   24
 
  CORPORATE AND OTHER
 
<TABLE>
<CAPTION>
                                                                 YEAR ENDED
                                                                DECEMBER 31,
                                                               --------------
                                                               1996      1995
                                                               -----     ----
                                                               (IN MILLIONS)
<S>                                                            <C>       <C>
Operating revenue...........................................   $   1     $  8
Operating expenses..........................................     111       --
                                                               -----     ----
  Operating income (loss)...................................   $(110)    $  8
                                                               =====     ====
</TABLE>
 
     Operating income for 1996 was $118 million lower than the prior year
primarily due to a $99 million employee separation and asset impairment charge
incurred in the first quarter of 1996. This decrease was partially offset by an
$8 million charge in the fourth quarter of 1996 for relocating the Company's
headquarters from El Paso, Texas to Houston, Texas in connection with the
acquisition of EPTPC. For a further discussion, see Note 10 of Item 8, Financial
Statements and Supplementary Data.
 
OTHER INCOME AND EXPENSE
 
YEAR ENDED DECEMBER 31, 1997, COMPARED TO YEAR ENDED DECEMBER 31, 1996
 
     Interest and debt expense for the year ended December 31, 1997, was $128
million higher than for the same period of 1996 due primarily to the level of
debt assumed in connection with the acquisition of EPTPC and the Company's debt
and capital realignment efforts.
 
     Other income for 1997 was $52 million higher than for 1996 primarily due to
an increase in equity and other income resulting from the Company's expanding
international activities and the acquisition of EPTPC.
 
YEAR ENDED DECEMBER 31, 1996, COMPARED TO YEAR ENDED DECEMBER 31, 1995
 
     Interest and debt expense for the year ended December 31, 1996, was $24
million higher than for the same period of 1995 due to an increase in EPG's
short-term and long-term borrowings and the debt assumed in connection with the
acquisition of EPTPC.
 
     The decrease in other income of $2 million is principally due to a
reduction in the allowance for funds used during construction for the year ended
December 31, 1996 resulting from a decrease in the average balance of
construction work in progress in 1996.
 
                        LIQUIDITY AND CAPITAL RESOURCES
 
CASH FROM OPERATING ACTIVITIES
 
     Net cash provided by operating activities was $280 million higher for the
year ended December 31, 1997, compared to the same period of 1996. This increase
was primarily a result of the acquisition of EPTPC, income tax refunds in 1997,
and prepayments from EPG's customers for risk-sharing revenues. The increase was
partially offset by higher interest payments resulting from debt assumed in the
acquisition of EPTPC, dividends on EPTPC's Series A Preferred Stock, a rate
refund to TGP's customers paid in March 1997, and a rate refund to EPG's
customers paid in August 1997.
 
CASH FROM INVESTING ACTIVITIES
 
     Net cash used in investing activities was $701 million higher for the year
ended December 31, 1997, compared to the same period of 1996. The increase was
primarily attributable to higher expenditures for joint ventures and equity
investments, capital expenditures, and acquisitions, as well as a decrease in
net cash related to the monetization of certain investments in 1996.
 
     Expenditures related to joint ventures and equity investments were
primarily attributable to the Company's international operations. The increase
in capital expenditures was related to construction activities
 
                                       20
<PAGE>   25
 
on the EPTPC and EPG pipeline systems as well as the purchase of gathering and
treating assets and other construction activities during 1997 by EPFS. The
increase attributable to acquisitions is due to the purchases of Gulf States Gas
Pipeline Company in October 1997 and certain subsidiaries of PacifiCorp in
December 1997. For a further discussion of these acquisitions, see Note 2 of
Item 8, Financial Statements and Supplementary Data. The decrease in net cash
from the monetization of certain investments is related to the sales in 1996 of
the exploration and production investments of TGP and a 70 percent equity
interest in certain Australian pipelines. Offsetting the increase in net cash
used in investing activities was the collection of a $53 million note receivable
for the Company's partnership in a 103 MW cogeneration plant in Florida.
 
     The Company's planned capital and investment expenditures for 1998 of $754
million, exclusive of the DeepTech acquisition (see Item 1, Business), 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, available
capacity under existing credit facilities, and/or the issuance of other
long-term debt, trust securities, or equity.
 
CASH FROM FINANCING ACTIVITIES
 
     Net cash provided by financing activities was $51 million for the year
ended December 31, 1997, an increase of $176 million from net cash used of $125
million for the year ended December 31, 1996. The increase was due in large part
to the Company's realignment of its debt and capital structure following the
EPTPC acquisition. Specifically, the increase is attributable to net cash
provided by commercial paper borrowings, the issuance of long-term debt by TGP
and the sale by EPG of 3 million shares of its common stock. Net cash provided
by financing activities was used for general corporate purposes and to fund net
revolving credit facility repayments, long-term debt retirements, and common
stock dividend payments. Net cash provided by financing activities was also
offset by the decrease in proceeds from project financing related to the 1996
refinancing of the Company's interest in certain Australian pipelines.
 
     Since November 1994, the Company has been authorized by the Board to
repurchase up to 5.5 million shares of its common stock. Shares repurchased are
held in EPG's treasury and are expected to be used in conjunction with EPG stock
compensation plans and for other corporate purposes. Pursuant to the
authorization, the Company had repurchased 4.7 million shares as of December 31,
1995. There were no common stock repurchases in 1996 and 1997. In January 1998,
the Board approved a new 5 million share common stock repurchase authority to
replace the November 1994 repurchase authority. The repurchase authority
increased to 10 million shares as a result of the two-for-one stock split
discussed in Item 5, Market for Registrant's Common Equity and Related
Stockholder Matters. The timing and amount of share repurchases, if any, will
depend upon the availability and alternate uses of capital, market conditions
and other factors.
 
     Future funding for long-term debt retirements, dividends, and other
financing expenditures is expected to be provided by internally generated funds,
commercial paper issuances, available capacity under existing credit facilities,
and/or the issuance of other long-term debt, trust securities, or equity.
 
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, EPG established a new $750 million
5-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"). Initially, the interest rate
will be a 32.5 basis point spread over LIBOR and the spread will vary based on
EPG's long-term debt credit rating. This facility replaced EPG's $750 million
five-year revolving credit facility and $250 million 364-day revolving credit
facility which were established in November 1996. 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 5-year portion of the new Revolving Credit Facility with TGP
designated as the borrower. The remainder of the availability under the
 
                                       21
<PAGE>   26
 
Revolving Credit Facility is expected to be used for general corporate purposes
including, but not limited to, backstopping EPG's $1 billion commercial paper
program.
 
     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).
 
     All of the Company's senior debt issues have been given investment grade
ratings by Standard & Poors and Moody's. The Company must comply with various
restrictive covenants contained in its debt agreements which include, among
others, maintaining a consolidated debt and guarantees to capitalization ratio
no greater than 70 percent. In addition, the Company's subsidiaries on a
consolidated basis (as defined in the agreements) may not incur debt obligations
which would exceed $300 million in the aggregate, excluding acquisition debt,
project financing, and certain refinancings. As of December 31, 1997, EPG's
consolidated debt and guarantees to capitalization ratio (as defined in the
agreements) was 58 percent and debt obligations of EPG subsidiaries in excess of
permitted debt did not exceed $300 million on a consolidated basis.
 
     In December 1997, EPG filed a shelf registration statement pursuant to
which EPG may offer up to $900 million (including $250 million transferred from
prior shelf registrations) of common or preferred equities, various forms of
debt securities (including convertible debt securities), and various types of
trust securities from time to time as determined by market conditions. In March
1998, the El Paso Energy Capital Trust I, a Delaware business trust sponsored by
the Company, issued 6.5 million 4 3/4% trust convertible preferred securities.
The sole assets of the trust are approximately $335 million principal amount
of 4 3/4% convertible subordinated debentures due 2028 of the Company. As a
result of such offering, EPG has approximately $565 million of capacity
remaining under its shelf registrations to issue public securities registered
thereunder. In addition, TGP has approximately $100 million remaining under its
February 1997 shelf registration.
 
     In March 1998, EPG retired its outstanding 8 5/8% debentures in the amount
of $16.8 million.
 
COMMITMENTS AND CONTINGENCIES
 
  Indonesian Economic Difficulties
 
     The Company owns a 47.5 percent interest in a power generating plant in
Sengkang, South Sulawesi, Indonesia, with a book value at December 31, 1997 of
approximately $19 million. Recent economic events in Indonesia have resulted in
the devaluation of the Indonesian Rupiah and delays or cancellations of certain
infrastructure power projects in that country. The Company has met with PLN and
the Indonesian Minister of Finance to discuss the terms of its power sales
agreement in light of the economic problems. While the Company cannot predict
the ultimate outcome of Indonesia's financial difficulties or the impact of such
matters to the Company, it believes PLN, with the backing of the Office of the
Minister of Finance, will honor all current invoices on the Sengkang project in
full and therefore, the current economic difficulties in Indonesia will not have
a material adverse effect on the Company's financial position or results of
operations.
 
  Capital Commitments
 
     At December 31, 1997, the Company had capital and investment commitments of
$254 million, which are expected to be funded through cash provided by
operations 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.
 
  Purchase Obligations
 
     In connection with the financing commitments of certain joint ventures, TGP
has entered into unconditional purchase obligations for products and services
totaling $99 million at December 31, 1997. TGP's annual obligations under these
agreements are $22 million for the year 1998, $21 million for the years
 
                                       22
<PAGE>   27
 
1999 and 2000, $11 million for the year 2001, $4 million for the year 2002, and
$20 million in total thereafter. Prior to August 1997, TGP had an obligation to
purchase 30 percent of the output of the Great Plains coal gasification
project's original design capacity through July 2009. TGP has executed a
settlement of this contract as a 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.
 
  Guarantees
 
     EPG has guaranteed various obligations of its subsidiaries, which
obligations are not expected to exceed $400 million. For further information,
see Note 5 of Item 8, Financial Statements and Supplementary Data.
 
  Rates and Regulatory Matters
 
     TGP -- In February 1997, TGP filed with FERC a settlement of all issues
related to the recovery by TGP of its GSR and other transition costs and related
proceedings (the "GSR Stipulation and Agreement"). In April 1997, FERC approved
the settlement and TGP implemented the settlement on May 1, 1997. Under the
terms of the GSR Stipulation and Agreement, TGP is entitled to collect from
customers up to $770 million, of which approximately $682 million has been
collected as of December 31, 1997. TGP is entitled to recover additional
transition costs, up to the remaining $88 million, through a demand
transportation surcharge and an interruptible transportation surcharge. The
demand transportation surcharge portion is scheduled to be recovered over a
period extending through December 1998. 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.
 
     In December 1994, TGP filed for a general rate increase with FERC and in
April 1996, it filed 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. In October 1996,
FERC approved the stipulation with certain modifications and clarifications
which are not material. In January 1997, FERC issued an order denying requests
for rehearing of that order. 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 had provided a reserve for these rate refunds as
revenues were collected. One party, a competitor of TGP, filed with the Court of
Appeals a Petition for Review of the FERC orders.
 
     In July 1997, FERC issued an order on rehearing of its July 1996 order
addressing cost allocation and rate design issues of TGP's 1991 general rate
proceeding. All cost of service issues were previously resolved pursuant to a
settlement that was approved by FERC. In the July 1996 order, FERC remanded to
the presiding ALJ the issue of proper allocation of TGP's New England lateral
costs. In the July 1997 order on rehearing, FERC clarified, among other things,
that although the ultimate resolution as to the proper allocation of costs will
be applied retroactively to July 1, 1995, the cost of service settlement does
not allow TGP to recover from other customers amounts that TGP may ultimately be
required to refund. TGP has filed with the Court of Appeals a Petition for
Review of the FERC orders on this issue. In December 1997, the ALJ issued his
decision on the proper allocation of the New England lateral costs. The decision
adopts a methodology that economically approximates TGP's current methodology.
The ALJ's decision is pending before FERC.
 
     In October 1997, TGP filed its cashout report for the period September 1995
through August 1996. TGP previously filed cashout reports for the period
September 1993 through August 1995. TGP's October 1997 filing showed a
cumulative loss of $11 million that would be rolled forward to the next cashout
period pursuant to its tariff. FERC has requested additional information and
justification from TGP as to its cashout methodology and reports. TGP's cashout
methodology and reports are currently pending before FERC.
 
                                       23
<PAGE>   28
     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 three 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, 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.
 
     EPG -- In June 1995, EPG filed with FERC for approval of new system rates
for mainline transportation to be effective January 1, 1996. In March 1996, EPG
filed a comprehensive offer of settlement to resolve that proceeding as well as
issues surrounding certain contract reductions and expirations that were to
occur from January 1, 1996 through December 31, 1997. In April 1997, FERC
approved EPG's settlement as filed and determined that only the contesting
party, Edison, should be severed for separate determination of the rate it
ultimately pays EPG. Hearings to determine Edison's rates are scheduled to begin
in April 1998. Pending the outcome of those hearings, Edison continues to pay
the filed rates, subject to refund, and EPG continues to provide a reserve for
such potential refunds. In July 1997, FERC issued an order denying the requests
for rehearing of the April 1997 order and the settlement was implemented
effective July 1, 1997. Edison and GPM Corporation, a competitor of EPG, have
filed with the Court of Appeals separate petitions for review of FERC's April
1997 and July 1997 orders.
 
     The rate settlement establishes, among other things, base rates through
December 31, 2005. Such rates escalate annually beginning in 1998. In addition,
the settlement provides for settling customers (i) to pay $295 million
(including interest) as a risk sharing obligation, which approximates 35 percent
of anticipated revenue shortfalls over an 8 year period, resulting from the
contract reductions and expirations referred to above, (ii) to receive 35
percent of additional revenues received by EPG, above a threshold, for the same
eight-year period, and (iii) to have the base rates increase or decrease if
certain changes in laws or regulations results in increased or decreased costs
in excess of $10 million a year. In accordance with the terms of the rate
settlement, EPG's refund obligation (including interest) was approximately $194
million. EPG refunded $61 million to customers in August 1997, and in accordance
with certain customers' elections, the remaining $133 million of refund
obligation was applied towards their $295 million risk sharing obligation. An
additional $75 million of the obligation was paid to EPG in August 1997 and the
$87 million balance, including interest, will be collected by the end of 2003.
At December 31, 1997 the remaining unearned balance of the risk sharing amount
collected was $189 million which will be recognized in earnings ratably through
2003.
 
     The contract reductions and expirations referred to above resulted in EPG's
having, as of January 1, 1998, approximately 1.6 Bcf/d (or 34 percent) less of
total capacity committed under contracts requiring the payment of full tariff
reservation rates. Effective January 1, 1998, this uncommitted capacity had an
annual value, at full tariff reservation rates, of approximately $171 million.
 
     EPG has substantially offset the effects of these reductions in firm
capacity commitments through the rate settlement provisions referred to above,
by implementing cost control programs, and by actively seeking new markets, and
pursuing attractive opportunities to increase traditional market share. The new
markets EPG has targeted include various natural gas users in California which
were served indirectly through SoCal and PG&E, as well as new markets off the
east end of its system. In addition to other arrangements, in October 1997, EPG
entered into three contracts with NGC for the sale of all of its firm capacity
available as of January 1, 1998 to California (approximately 1.3 Bcf) for a
two-year period beginning January 1, 1998 at rates negotiated pursuant to EPG's
tariff provisions and FERC policies. EPG anticipates realizing at least $70
million in revenues (which will be subject to the revenue sharing provisions of
the rate settlement) under these contracts over the two-year period. The
contracts have a transport-or-pay provision requiring NGC to pay a minimum
charge equal to the reservation component of the contractual charge on at least
50 percent of the contracted volumes in each month in 1998 and on at least 72
percent of the contracted volumes each month in 1999. In December 1997, EPG made
a tariff filing to implement several negotiated rate contracts, including those
with NGC. In a protest to this filing made in January 1998, three shippers
                                       24
<PAGE>   29
 
(producers/ marketers) requested FERC to require EPG to eliminate certain
provisions from the NGC contracts, to publicly disclose and repost the contracts
for competitive bidding, and to suspend their effectiveness. In an order issued
in January 1998, FERC rejected several of the arguments made in the protest and
allowed the contracts to become effective as of January 1, 1998 subject to
refund and to the outcome of a technical conference, which was held in March
1998. The technical conference addressed the operation of certain of the
contracts' provisions, including those which provide for crediting (to amounts
otherwise due under the contracts) of certain interruptible revenues which might
be received by EPG, and the protesters' claims that the contracts are
anti-competitive. Following written submissions by the parties, FERC will decide
what action to take. Assuming FERC allows the contracts to remain in effect, it
cannot be predicted at this time whether EPG will be able to remarket this
capacity after 1999 or the terms under which it may be remarketed.
 
     Under FERC procedures, take-or-pay cost recovery filings may be challenged
by pipeline customers on prudence and certain other grounds. Certain parties
sought review in the Court of Appeals of FERC's determination in the October
1992 order that certain buy-down/buy-out costs were eligible for recovery. In
January 1996, the Court of Appeals remanded the order to FERC with direction to
clarify the basis for its decision that the take-or-pay buy-down/buy-out costs
were eligible for recovery. In March 1997, following a technical conference and
the submission of statements of position and replies, FERC issued an order
determining that the costs related to all but one of EPG's disputed contracts
were eligible for recovery. The costs ruled ineligible for recovery totaled
approximately $3 million, including interest, and were refunded to customers in
the second quarter of 1997. In October 1997, FERC issued an order denying the
challenging parties' request for rehearing of the March 1997 order in most
respects, but determined that the costs incurred pursuant to two additional EPG
contracts were ineligible for recovery. These costs, including interest, totaled
approximately $9 million, and were refunded to customers in February 1998. The
challenging parties, which claim that EPG should be required to refund up to an
additional $31 million, excluding interest, have filed a petition for review of
the FERC order in the Court of Appeals.
 
     In an order issued in April 1997 in the proceeding involving the spin down
of EPG's gathering facilities to EPFS, FERC found that EPG acted appropriately
in not including its Chaco Compressor Station ("Chaco Station") in the
facilities to be transferred to EPFS, and that the Chaco Station had been
correctly functionalized by EPG as a transmission facility. Requests for
rehearing of this order were filed by Williams Field Services Group and GPM
Corporation. In a November 1997 order, FERC reversed its previous decision and
found that the Chaco Station is a gathering facility. EPG and others have sought
rehearing of this order, and the matter is still pending.
 
     Separately, in November 1996, GPM Corporation filed a complaint, as
amended, with FERC alleging that EPG's South Carlsbad compression facilities
were gathering facilities and were improperly functionalized by EPG as
transmission facilities. In a November 1997 order, FERC concluded that the South
Carlsbad Compressor Station performed a gathering function and directed EPG to
transfer the facility to EPFS. FERC held, however, that its November 1997
rulings would not affect the base settlement rates provided for under the 1996
rate settlement described above. EPG and others have sought rehearing of this
order, and the matter is still pending.
 
     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 and results of
operations.
 
  Legal Proceedings
 
     See Item 3, Legal Proceedings which is incorporated herein by reference.
 
                                       25
<PAGE>   30
 
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, 1997, the Company had a reserve of
approximately $284 million for the following environmental contingencies which
the Company anticipates incurring through 2027: (i) expected remediation costs
and associated onsite, offsite and groundwater technical studies of
approximately $257 million; and (ii) other costs of approximately $27 million.
 
     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 33 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, 1997, the
Company has estimated its share of the remediation costs at these sites to be
between $68 million and $83 million and has provided reserves that it believes
are adequate for such costs. Because 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 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 or results of
operations.
 
     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 their
initial stages and accordingly, it is not possible to predict the outcome.
 
     For a further discussion of specific environmental matters, see Item 3,
Legal Proceedings.
 
OTHER
 
  Acquisition of DeepTech International, Inc.
 
     In March 1998, the Company and Deeptech entered into a definitive agreement
whereby the Company will acquire DeepTech as well as DeepTech's combined
ownership interest in Levianthan. Leviathan is a publicly traded partnership
that produces, processes, gathers, transports and markets oil and gas located in
the offshore Gulf of Mexico. In connection with the acquisition, the Company
will acquire the 15 percent minority equity interest in the holding company
through which DeepTech owns its Leviathan interests. After the transactions, the
Company will own 100 percent of the general partner of Leviathan and a 27.3
percent effective ownership interest in Leviathan. Each holder of DeepTech
common stock will receive as
consideration $14 per share either in cash or EPG common stock, at such holder's
election, subject to a minimum and maximum exchange ratio of approximately
0.1867 and 0.28 shares, respectively, of EPG common stock for each share of
DeepTech common stock. The acquisition will be accounted for as a purchase with
a total purchase price of approximately $450 million. Completion of the
transactions is subject to various conditions including the receipt of required
regulatory and stockholder approvals and other customary conditions, and no
assurance can be given that the transactions will be successfully completed.
 
                                       26
<PAGE>   31
 
  Year 2000
 
     The Company has established an executive steering committee and a project
team to coordinate the assessment, remediation, testing and implementation of
the necessary modifications to its key computer applications (which consist of
internally developed computer applications, third party software, hardware and
embedded chip systems) to assure that such systems and related processes will
remain functional.
 
     The assessment phase related to internally developed computer applications
has been completed and the cost estimate for making the necessary changes to
such systems, including implementation and testing efforts, is approximately $8
million to be spent in 1998 and 1999. These estimates were based on various
factors including availability of internal and external resources and complexity
of the software applications. The recent upgrade of various systems,
particularly the financial systems, to a Year 2000 compliant client/server
platform have greatly reduced or eliminated concerns in those areas.
 
     The assessment phase for the third party software and hardware impacts is
continuing, with completion of that phase and an estimate of costs necessary to
modify or replace those systems to be available in the second quarter of 1998.
Included in this phase of the project is the effort to obtain representations
and assurances from third party vendors that their software and hardware
products being used by the Company are or will be Year 2000 compliant.
Implementation and testing phases are expected to be completed by mid 1999.
 
     It is the Company's goal to ensure that all of the critical systems and
processes which are under its direct control remain functional. However, because
certain systems may be interrelated with systems outside the control of the
Company, there can be no assurances that all implementations will be successful.
Management does not expect the costs to modify its systems or to correct any
unsuccessful system implementations to have a material adverse impact on the
Company's financial position or results of operations.
 
  Employee Separation and Asset Impairment Charge
 
     During the first quarter of 1996, the Company adopted a program to reduce
operating costs through work force reductions and improved work processes and
adopted SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of. As a result of the workforce reduction
program and the adoption of SFAS No. 121, the Company recorded a special charge
of $99 million ($47 million for employee separation costs and $52 million for
asset impairments) in the first quarter of 1996. For a further discussion, see
Note 10 of Item 8, Financial Statements and Supplementary Data.
 
  SFAS No. 71, Accounting for the Effects of Certain Types of Regulation
 
     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
those accounting methods used by non-regulated entities. Changes in the
regulatory and economic environment may, at some point in the future, create
circumstances in which the application of regulatory accounting principles would
no longer be appropriate. If the Company's regulated businesses fail to qualify
under these accounting principles, an amount would be charged to earnings as an
extraordinary item in accordance with SFAS No. 101, Regulated
Enterprises -- Accounting for Discontinuation of Application of SFAS No. 71. At
December 31, 1997, this amount was estimated to be approximately $54 million,
net of income taxes. Any potential charge would be non-cash and would not
directly effect the regulated companies' ability to seek recovery of the
underlying deferred costs in their future rate proceedings or their ability to
collect the rates set thereby. For a further discussion of SFAS No. 71 issues,
see Note 1 of Item 8, Financial Statements and Supplementary Data.
 
     Effective January 1, 1996, EPG transferred certain gathering and processing
facilities to EPFS. FERC had previously determined that, upon the transfer to
EPFS, the facilities would be exempt from FERC jurisdiction. Accordingly, the
provisions of SFAS No. 71 do not apply to EPFS's transactions and balances
effective January 1, 1996. The discontinuance of the application of SFAS No. 71
to EPFS did not have a material impact on the Company's financial position or
results of operations.
 
                                       27
<PAGE>   32
 
  FERC Compliance Audits
 
     TGP and EPG, as with all interstate pipelines, are subject to a FERC audit
of their books and records. EPG currently has an open audit covering the years
1990 through 1995. FERC audit staff is expected to issue its audit report in
1998.
 
  Change in Corporate Structure
 
     The Company intends to adopt, subject to certain conditions, a holding
company structure whereby the Company and its subsidiaries would become direct
and indirect subsidiaries of a newly formed Delaware holding company. Pursuant
to the holding company reorganization, holders of shares of common stock of EPG
would become holders on a share-for-share basis of shares of common stock of the
holding company with the result that the holding company would replace EPG as
the publicly-held corporation, and all stockholders of EPG immediately prior to
such reorganization would own the same number of shares of holding company
common stock immediately after the reorganization as the EPG common stock held
immediately before the reorganization. The change to a holding company structure
would be tax free for federal income tax purposes to stockholders of EPG and may
be effected without a vote of stockholders under applicable Delaware law.
 
     The holding company reorganization is subject to the satisfaction of
certain conditions, including among other things: (i) approval of the holding
company common stock and preferred stock purchase rights for trading on the New
York Stock Exchange; (ii) a favorable no-action ruling from the SEC concerning
the absence of a requirement for a registration under the Securities Act of 1933
of the holding company common stock to be issued in the reorganization and
certain other securities law issues; and (iii) a favorable private letter ruling
from the IRS or opinion of counsel, in either case substantially to the effect
that the change to the holding company structure will be tax free for federal
income tax purposes to stockholders. No assurance can be given that the
conditions to forming the holding company structure will be satisfied or, if
satisfied, that the holding company structure will be implemented.
 
                             RECENT PRONOUNCEMENTS
 
     In 1997, the Company adopted or applied the relevant provisions of SFAS No.
123, Accounting for Stock-Based Compensation SFAS No. 125, Accounting for
Transfers and Servicing of Financial Assets and Extinguishment of Liabilities,
SFAS No. 127, Deferral of the Effective Date of Certain Provisions of FASB
Statement No. 125, SFAS No. 128, Earning per Share, SFAS No. 129, Disclosure of
Information about Capital Structure, the Securities and Exchange Commission's
Financial Reporting Release No. 48, Disclosure of Derivative and Other Financial
Instruments and Statement of Position No. 96-1, Environmental Remediation
Liabilities. The adoption or application of these pronouncements did not have a
material impact on the Company's financial position or results of operations.
For further discussion, see Note 1 of Item 8, Financial Statements and
Supplementary Data.
 
  Comprehensive Income
 
     In June 1997, the Financial Accounting Standards Board issued SFAS No. 130,
Reporting Comprehensive Income, which establishes standards for reporting and
display of comprehensive income and its components in a full set of
general-purpose financial statements. SFAS No. 130 requires that all items that
are required to be recognized under accounting standards as components of
comprehensive income be reported in a financial statement that is displayed with
the same prominence as other financial statements. This pronouncement is
effective for the financial statements for periods beginning after December 15,
1997. The Company is planning to adopt this statement in the first quarter of
1998.
 
  Segment Reporting
 
     In June 1997, the Financial Accounting Standards Board issued SFAS No. 131,
Disclosures about Segments of an Enterprise and Related Information, which
establishes, among other things, the way that public business enterprises report
information about operating segments in annual and interim financial statements
issued to shareholders. It also establishes standards for related disclosures
about products and
                                       28
<PAGE>   33
 
services, geographic areas, and major customers. This pronouncement is effective
for financial statements for periods beginning after December 15, 1997. The
Company is planning to adopt this statement in the first quarter of 1998 and the
number of reportable segments is expected to increase.
 
  Pensions and Other Postretirement Benefits Disclosures
 
     In February 1998, SFAS No. 132, Employers' Disclosures about Pensions and
Other Postretirement Benefits, was issued by the Financial Accounting Standards
Board to standardize related disclosure requirements. SFAS No. 132 requires that
additional information be disclosed regarding changes in the benefit obligation
and fair values of plan assets, and eliminates certain disclosures no longer
considered useful, including general descriptions of the plans. Aggregation of
information about certain plans is also permitted. This statement does not
change the requirements for the measurement and recognition of those plans. It
is effective for fiscal years beginning after December 15, 1997. The Company is
currently evaluating the effect of this pronouncement.
 
                                       29
<PAGE>   34
 
     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, the Company
cautions 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, the Company or its management expresses 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.
 
     Taking into account the foregoing, the following are identified as
important factors that could cause actual results to differ materially from
those expressed in any forward-looking statement made by, or on behalf of, the
Company:
 
HIGHLY COMPETITIVE INDUSTRY
 
          The ability to maintain or increase current transmission, gathering,
     processing, and sales volumes, or to remarket unsubscribed capacity, can be
     subject to the impact of future weather conditions, including those that
     favor hydroelectric generation or other alternative energy sources; price
     competition; drilling activity and supply availability; and service
     competition, especially due to excess pipeline capacity into California.
     Future profitability also may be affected by the Company's ability to
     compete with the services offered by other energy enterprises which may be
     larger, offer more services, and possess greater resources. The ability to
     negotiate new contracts and to renegotiate existing contracts (70 percent
     of TGP's contracts are expiring over the next three years, principally in
     November 2000) could be adversely affected by the proposed construction by
     other parties of additional pipeline capacity, the viability of the
     Company's expansion projects, reduced demand due to higher gas prices, the
     availability of alternative energy sources, and other factors that are not
     within its control. For a further discussion see
     Part I, Item 1, Business -- Natural Gas Transmission -- Markets and
     Competition.
 
IMPACT OF NATURAL GAS AND NATURAL GAS LIQUIDS PRICES
 
          The value of natural gas transmission services is based on an all-in
     cost, including the cost of the natural gas. Therefore, the Company's
     ability to compete with other transporters is impacted by natural gas
     prices in the supply basins connected to its pipeline systems compared to
     prices in other gas producing regions, especially Canada. Revenues
     generated by the Company from its 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 the Company's
     expanding gathering and processing operations in the offshore Gulf of
     Mexico (including the proposed acquisition of DeepTech's combined ownership
     interest in Leviathan -- See Item 1, Business) is subject to continued
     development of additional oil and gas reserves and the ability to access
     such additional reserves to offset the natural decline from existing wells
     connected to its systems. 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 the Company's gathering and processing
     facilities, are caused by a number of factors, including regional, domestic
     and international 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.
 
USE OF DERIVATIVE FINANCIAL INSTRUMENTS
 
          In the ordinary course and conduct of its business, some of the
     Company's non-regulated subsidiaries are engaged in the gathering,
     processing and marketing of natural gas and other energy
 
                                       30
<PAGE>   35
 
     commodities and utilize futures and option contracts traded on the New York
     Mercantile Exchange and OTC options and price and basis swaps with other
     gas merchants and financial institutions. The Company could incur financial
     losses in future periods as a result of volatility in the market values of
     the underlying commodities or if one of its counterparties fails to perform
     under a contract. For additional information concerning the Company's
     derivative financial instruments, see Item 7A, Quantitative and Qualitative
     Disclosures About Market Risks and Note 4 of Item 8, Financial Statements
     and Supplementary Data.
 
ACQUISITIONS AND INVESTMENTS
 
          Opportunities for growth through acquisitions and investments in joint
     ventures, and future operating results and the success of such acquisitions
     and joint ventures within and outside the U.S. may be subject to the
     effects of, and changes in, U.S. and foreign trade and monetary policies,
     laws and regulations, political and economic developments, inflation rates,
     and the effects of taxes and operating conditions. Activities in areas
     outside the U.S. also 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
     currency and other economic problems). Such legal and regulatory events and
     other unforeseeable obstacles may be beyond the Company's control or
     ability to manage.
 
POTENTIAL ENVIRONMENTAL LIABILITIES
 
          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. For additional information concerning the
     Company's environmental matters, see Note 5 of Item 8, Financial Statements
     and Supplementary Data.
 
OPERATING HAZARDS AND UNINSURED RISKS
 
          While the Company maintains 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 the Company.
 
POTENTIAL LIABILITIES RELATED TO THE MERGER
 
          The amount of the actual and contingent liabilities of EPTPC, which
     remained the liabilities of the Company after the Merger, could vary
     materially from the amount estimated by the Company, 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 the Company, under certain legal
     theories which may or may not be applicable to the situation, to assume
     responsibility for such obligations, which could have a material adverse
     effect on the Company.
 
POTENTIAL FEDERAL INCOME TAX LIABILITIES
 
          In connection with the Merger and Distributions, the IRS issued a
     private letter ruling to Old Tenneco, in which it ruled that for U.S.
     federal income tax purposes (i) 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, (ii) the Merger
     would constitute a tax-free reorganization, and (iii) that certain other
     transactions effected in connection with the Merger and Distributions 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,
 
                                       31
<PAGE>   36
 
     New Tenneco and Newport News Shipbuilding Inc. have agreed to indemnify
     EPTPC for a defined portion of such tax liabilities.
 
FINANCING AND INTEREST RATE EXPOSURE RISKS
 
          The business and operating results of the Company 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 the Company, or credit ratings.
 
YEAR 2000
 
          While the Company is taking steps, including the assessment,
     remediation, testing and implementation of changes to applications,
     hardware and software to mitigate any adverse effects of the Year 2000 date
     change on its customers and business operations, the failure of the Company
     or third-party entities to achieve Year 2000 compliance may adversely
     effect the Company. For additional information on the Company's Year 2000
     strategy, see Note 5 of Item 8, Financial Statements and Supplementary
     Data.
 
                                       32
<PAGE>   37
 
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 changing
commodity prices. The Company's policy is to manage commodity price risk through
a variety of financial instruments, which are entered into for trading purposes
and include forward contracts involving cash settlements 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 variable price for
the commodity, options, and other contractual arrangements.
 
     The table below presents market value of commodity contracts and the
hypothetical loss of future earnings the Company would incur on such commodity
contracts should commodity prices fluctuate by 10 percent of their respective
market values as of December 31, 1997:
 
<TABLE>
<CAPTION>
                                                                             GAIN (LOSS) FROM
                                                                                10% CHANGE
                                                              MARKET VALUE          IN
                                                              OF COMMODITY      COMMODITY
                       COMMODITY TYPE                          CONTRACTS          PRICES
                       --------------                         ------------   ----------------
                                                                       (IN MILLIONS)
<S>                                                           <C>            <C>
Natural gas.................................................     $  26            $  (1)
Power.......................................................        (2)               1
Petroleum products..........................................        (1)              (1)
</TABLE>
 
     In addition to energy commodities, the Company manages risk through the
following financial instruments as listed in the table below.
 
<TABLE>
<CAPTION>
                                                           EXPECTED FISCAL YEAR OF MATURITY
                                                -------------------------------------------------------
                                                1998   1999    2000   2001    2002   THEREAFTER   TOTAL
                                                ----   -----   ----   -----   ----   ----------   -----
                                                                 (DOLLARS IN MILLIONS)
<S>                                             <C>    <C>     <C>    <C>     <C>    <C>          <C>
Interest Rate Swap
--------------------
  Variable to fixed rate-notional amounts.....         $  29                  $ 85                $114
  Average rate paid...........................           8.3%                  8.4%
  Average received rate(1)....................           5.8%                  5.9%
Equity Swap
  Interest to dividend -- notional amount.....         $ 100                                      $100
  Average interest paid(1)....................           6.6%
  Received dollars............................             *
</TABLE>
 
---------------
 
(1) The variable rates presented are the average forward rates for the remaining
    term of each contract.
 
 *  The Company receives dividends on the CAPSA stock to the extent of the
    counterparty's equity interest of 18.5 percent and participates in the
    market appreciation or depreciation of the underlying investment whereby the
    Company will realize the appreciation or fund any depreciation upon
    termination or expiration of the swap transaction.
 
     For a further discussion, see Note 4 of Item 8, Financial Statements and
Supplementary Data.
 
                                       33
<PAGE>   38
 
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
                          EL PASO NATURAL GAS COMPANY
 
                       CONSOLIDATED STATEMENTS OF INCOME
                 (IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
 
<TABLE>
<CAPTION>
                                            YEAR ENDED DECEMBER 31,
                                           --------------------------
                                            1997      1996      1995
                                           ------    ------    ------
<S>                                        <C>       <C>       <C>
Operating revenues
  Transportation........................   $1,200    $  534    $  511
  Natural gas, liquids and power........    4,110     2,359       403
  Gathering and processing..............      204        85        73
  Other.................................      124        34        51
                                           ------    ------    ------
                                            5,638     3,012     1,038
                                           ------    ------    ------
Operating expenses
  Cost of gas and other products........    4,113     2,277       402
  Operation and maintenance.............      676       322       312
  Depreciation, depletion, and
     amortization.......................      236       101        72
  Employee separation and asset
     impairment charge..................       --        99        --
  Taxes, other than income taxes........       92        43        40
                                           ------    ------    ------
                                            5,117     2,842       826
                                           ------    ------    ------
Operating income........................      521       170       212
                                           ------    ------    ------
Other (income) and expense
  Interest and debt expense.............      238       110        86
  Other, net............................      (57)       (5)       (7)
                                           ------    ------    ------
                                              181       105        79
                                           ------    ------    ------
Income before income taxes and minority
  interest..............................      340        65       133
Income tax expense......................      129        25        48
                                           ------    ------    ------
Income before minority interest.........      211        40        85
Minority interest
  Preferred stock dividend of
     subsidiary.........................       25         2        --
                                           ------    ------    ------
Net income..............................   $  186    $   38    $   85
                                           ======    ======    ======
Basic earnings per common share.........   $ 3.27    $ 1.06    $ 2.47
                                           ======    ======    ======
Diluted earnings per common share.......   $ 3.18    $ 1.04    $ 2.47
                                           ======    ======    ======
Basic average common shares
  outstanding...........................       57        36        34
                                           ======    ======    ======
Diluted average common shares
  outstanding...........................       59        37        34
                                           ======    ======    ======
</TABLE>
 
                 The accompanying Notes are an integral part of
                    these Consolidated Financial Statements.
 
                                       34
<PAGE>   39
 
                          EL PASO NATURAL GAS COMPANY
 
                          CONSOLIDATED BALANCE SHEETS
                   (IN MILLIONS, EXCEPT COMMON SHARE AMOUNTS)
 
                                     ASSETS
 
<TABLE>
<CAPTION>
                                                  DECEMBER 31,
                                          ----------------------------
                                              1997            1996
                                          ------------    ------------
<S>                                       <C>             <C>
Current assets
  Cash and temporary investments........     $  116          $  200
  Accounts and notes receivable, net
     Customer...........................        737             931
     Other..............................        252             342
  Inventories...........................         68              87
  Deferred income tax benefit...........        168             141
  Assets from commodity price risk
     management activities..............         96             103
  Regulatory assets.....................        116             202
  Other.................................         76              90
                                             ------          ------
          Total current assets..........      1,629           2,096
                                             ------          ------
Property, plant, and equipment, net.....      7,116           5,938
Other...................................        787             809
                                             ------          ------
          Total assets..................     $9,532          $8,843
                                             ======          ======
                 LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
  Accounts payable
     Trade..............................     $  787          $  588
     Other..............................         99             501
  Short-term borrowings (including
     current maturities of long-term
     debt)..............................        885             841
  Accrual for regulatory issues.........         22             309
  Liabilities from commodity price risk
     management activities..............         73              64
  Other.................................        598             540
                                             ------          ------
          Total current liabilities.....      2,464           2,843
                                             ------          ------
Long-term debt, less current
  maturities............................      2,119           2,215
                                             ------          ------
Deferred income taxes...................      1,550           1,092
                                             ------          ------
Postretirement benefits.................        285             309
                                             ------          ------
Other...................................        790             411
                                             ------          ------
Commitments and contingencies (See Note
  5)
Minority interest
  Preferred stock of subsidiary.........        300             296
                                             ------          ------
  Other minority interest...............         65              39
                                             ------          ------
Stockholders' equity
  Common stock, par value $3 per share;
     authorized 100,000,000 shares;
     issued 61,290,908 and 56,726,734
     shares, respectively...............        184             170
  Additional paid-in capital............      1,573           1,355
  Retained earnings.....................        327             227
  Less: Cumulative translation
        adjustment......................          7              --
        Treasury stock (at cost)
        1,473,416 and 1,451,922 shares,
        respectively....................         47              45
        Deferred compensation...........         71              69
                                             ------          ------
          Total stockholders' equity....      1,959           1,638
                                             ------          ------
          Total liabilities and
            stockholders' equity........     $9,532          $8,843
                                             ======          ======
</TABLE>
 
                 The accompanying Notes are an integral part of
                    these Consolidated Financial Statements.
 
                                       35
<PAGE>   40
 
                          EL PASO NATURAL GAS COMPANY
 
                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (IN MILLIONS)
 
<TABLE>
<CAPTION>
                                            YEAR ENDED DECEMBER 31,
                                          ---------------------------
                                           1997       1996      1995
                                          -------    -------    -----
<S>                                       <C>        <C>        <C>
Cash flows from operating activities
  Net income............................  $   186    $    38    $  85
  Adjustments to reconcile net income to
     net cash provided by operating
     activities
     Depreciation, depletion, and
       amortization.....................      236        101       72
     Deferred income taxes (benefit)....      195         (5)      30
     Undistributed earnings in equity
       investees........................       (3)        16       --
     Amortization of deferred
       compensation.....................       19          5       --
     Unearned risk-sharing revenue......      189         --       --
     Net take-or-pay recoveries.........       --         10       36
     Net employee separation and asset
       impairment charge................       --         76       --
     Other working capital changes, net
       of non cash transactions
       Accounts and notes receivable....      342       (168)     (11)
       Inventories......................       16         (5)       1
       Net commodity price risk
          management activities.........       16        (39)      --
       Regulatory asset.................       19         --       --
       Other current assets.............       47         77      (10)
       Accrual for regulatory issues....     (266)       135       --
       Accounts payable.................     (249)        65      (10)
       Other current liabilities........     (177)        (8)       2
  Other.................................        1         (7)       8
                                          -------    -------    -----
          Net cash provided by operating
            activities..................      571        291      203
                                          -------    -------    -----
Cash flows from investing activities
  Capital expenditures..................     (293)      (119)    (166)
  Investment in joint ventures and
     equity investees...................     (239)       (24)      --
  Net cash flow impact of
     acquisitions.......................     (213)       (35)     (23)
  Net cash flow impact from monetization
     of investments.....................        8        179       --
  Collection of note receivable from
     partnership........................       53         --       --
  Other.................................      (22)        (6)     (27)
                                          -------    -------    -----
          Net cash used in investing
            activities..................     (706)        (5)    (216)
                                          -------    -------    -----
Cash flows from financing activities
  Net commercial paper borrowings
     (repayments).......................      326       (203)      96
  Revolving credit borrowings...........       70        400       75
  Revolving credit repayments...........   (1,200)    (1,022)      --
  Long-term debt retirements............     (124)       (24)     (16)
  Long-term debt issuance...............      883        396       --
  Dividends paid........................      (77)       (53)     (45)
  Net proceeds from stock issuance......      152         --       --
  Proceeds from project financing.......       --        310       --
  Other.................................       21         71      (86)
                                          -------    -------    -----
          Net cash provided by (used in)
            financing activities........       51       (125)      24
                                          -------    -------    -----
Increase (decrease) in cash and
  temporary investments.................      (84)       161       11
Cash and temporary investments
  Beginning of period...................      200         39       28
                                          -------    -------    -----
  End of period.........................  $   116    $   200    $  39
                                          =======    =======    =====
</TABLE>
 
                 The accompanying Notes are an integral part of
                    these Consolidated Financial Statements.
 
                                       36
<PAGE>   41
 
                          EL PASO NATURAL GAS COMPANY
 
                CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
                 (IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<TABLE>
<CAPTION>
                                  COMMON STOCK     ADDITIONAL              CUMULATIVE    TREASURY STOCK
                                 ---------------    PAID-IN     RETAINED   TRANSLATION   ---------------     DEFERRED
                                 SHARES   AMOUNT    CAPITAL     EARNINGS   ADJUSTMENT    SHARES   AMOUNT   COMPENSATION
                                 ------   ------   ----------   --------   -----------   ------   ------   ------------
<S>                              <C>      <C>      <C>          <C>        <C>           <C>      <C>      <C>
January 1, 1995................    37      $112      $  455       $203        $ --         (2)     $(60)       $ --
  Net income...................                                     85
  Common stock dividend ($1.32
    per share).................                                    (45)
  Acquisition of treasury
    stock......................                                                            (2)      (57)
  Issuance of treasury stock
    for acquisition of Eastex
    Energy Inc.................                                     (3)                     1        21
  Issuance of treasury stock...                                                                       1
                                   --      ----      ------       ----        ----         --      ----        ----
December 31, 1995..............    37       112         455        240          --         (3)      (95)         --
  Net income...................                                     38
  Common stock dividend ($1.39
    per share).................                                    (50)
  Issuance of common stock for
    acquisition of EPTPC.......    19        56         857
  Restricted stock issuances...                          23                                 1        41         (74)
  Amortization of deferred
    compensation...............                                                                                   5
  Options exercised............     1         2          19         (1)                     1         9
  Other........................                           1
                                   --      ----      ------       ----        ----         --      ----        ----
December 31, 1996..............    57       170       1,355        227          --         (1)      (45)        (69)
  Net income...................                                    186
  Common stock dividend ($1.46
    per share).................                                    (86)
  Issuance of common stock, net
    of related costs...........     3        10         162
  Restricted stock issuances...               2          22                                           1         (23)
  Restricted stock
    forfeitures................                                                                      (3)          2
  Amortization of deferred
    compensation...............                                                                                  19
  Options exercised............     1         2          23
  Income tax benefit of options
    exercised..................                          11
  Translation adjustment.......                                                 (7)
                                   --      ----      ------       ----        ----         --      ----        ----
December 31, 1997..............    61      $184      $1,573       $327        $ (7)        (1)     $(47)       $(71)
                                   ==      ====      ======       ====        ====         ==      ====        ====
 
<CAPTION>
                                     TOTAL
                                 STOCKHOLDERS'
                                    EQUITY
                                 -------------
<S>                              <C>
January 1, 1995................     $  710
  Net income...................         85
  Common stock dividend ($1.32
    per share).................        (45)
  Acquisition of treasury
    stock......................        (57)
  Issuance of treasury stock
    for acquisition of Eastex
    Energy Inc.................         18
  Issuance of treasury stock...          1
                                    ------
December 31, 1995..............        712
  Net income...................         38
  Common stock dividend ($1.39
    per share).................        (50)
  Issuance of common stock for
    acquisition of EPTPC.......        913
  Restricted stock issuances...        (10)
  Amortization of deferred
    compensation...............          5
  Options exercised............         29
  Other........................          1
                                    ------
December 31, 1996..............      1,638
  Net income...................        186
  Common stock dividend ($1.46
    per share).................        (86)
  Issuance of common stock, net
    of related costs...........        172
  Restricted stock issuances...          2
  Restricted stock
    forfeitures................         (1)
  Amortization of deferred
    compensation...............         19
  Options exercised............         25
  Income tax benefit of options
    exercised..................         11
  Translation adjustment.......         (7)
                                    ------
December 31, 1997..............     $1,959
                                    ======
</TABLE>
 
                 The accompanying Notes are an integral part of
                    these Consolidated Financial Statements.
 
                                       37
<PAGE>   42
 
                          EL PASO NATURAL GAS COMPANY
 
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
  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 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 presentation. Such reclassifications have no impact on
reported net income or stockholders' equity.
 
  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 could differ from those
estimates.
 
  Accounting for the Acquisition of EPTPC
 
     On December 12, 1996, the Company acquired EPTPC through a business
combination accounted for as a purchase. To effect the purchase, a preliminary
allocation of the purchase price was assigned to the assets and liabilities
acquired pending the Company's analysis and assessment of its exposure to
contingencies assumed in the acquisition, as well as other components of the
purchase price allocation. As of December 31, 1997, the Company has completed
its analysis and, accordingly, has made adjustments for certain contingencies
including, among other things, litigation, environmental, and regulatory issues.
In addition, an independent appraisal of the fair value of the physical
properties acquired, which supports the amount allocated to the property, plant
and equipment of EPTPC was completed in 1997.
 
  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
those accounting methods used by non-regulated entities. Transactions that have
been recorded differently as a result of regulatory accounting requirements
include: transition costs to be recovered under a volumetric surcharge; 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 accounting conforms to the generally accepted accounting
principle of matching costs against the revenues to which they apply.
 
     Changes in the regulatory and economic environment may, at some point in
the future, create circumstances in which the application of regulatory
accounting principles will no longer be appropriate. If the Company's regulated
business fail to qualify under these accounting principles, an amount would be
charged to earnings as an extraordinary item in accordance with SFAS No. 101,
Regulated Enterprises -- Accounting for Discontinuation of Application of SFAS
No. 71. At December 31, 1997, this amount was estimated to be approximately $54
million, net of income taxes. Any potential charge would be non-cash and would
have no direct effect on the regulated companies' ability to seek recovery of
the underlying deferred costs in their future rate proceedings or on their
ability to collect the rates set thereby.
 
  Cash and Temporary Investments
 
     Short-term investments purchased with an original maturity of three months
or less are considered cash equivalents.
 
                                       38
<PAGE>   43
 
  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, 1997 and 1996, were $17
million and $60 million, respectively.
 
  Gas Imbalances
 
     The Company values gas imbalances due to or due from shippers and operators
at the appropriate index price. The gas imbalances are settled in cash or made
up in-kind.
 
  Inventories
 
     Inventories, consisting of materials and supplies and 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 $276 million and $189 million at December 31,
1997, and 1996, 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.
 
     Depreciation of the Company's regulated transmission facilities are
provided primarily using the composite method over the estimated useful lives of
the depreciable facilities. The rates for depreciation range from approximately
1 percent to 20 percent.
 
     Depreciation of the Company's nonregulated 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.
 
     Additional acquisition cost assigned to utility plant 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 over the estimated useful life of the properties.
 
     Costs of regulated properties that are not operating units, as defined by
FERC, which are retired, sold, or abandoned are charged or credited, net of
salvage, to accumulated depreciation and amortization. Gains or losses on sales
of operating units are credited or charged to income.
 
     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
 
     Goodwill and other intangibles are being amortized using the straight-line
method over periods ranging from 5 years to 40 years. The net balances of
intangible assets at December 31, 1997 and 1996, were $117 million and $116
million, 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 remedial
efforts are probable and the costs can be reasonably estimated. Estimates of the
liability are based upon currently available facts, existing technology
                                       39
<PAGE>   44
 
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 a regulatory asset.
 
  Price Risk Management Activities
 
     The Company utilizes derivative financial instruments to manage market
risks associated with certain energy commodities, interest rates, and foreign
currency exchange 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 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 settlements 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 variable price for
the commodity, options, and other contractual arrangements.
 
     Under mark-to-market accounting, financial instruments with third parties
are reflected at estimated market value, with resulting unrealized 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 from commodity
price risk management activities and liabilities from commodity 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 financial instruments reflects management's best
estimate considering various factors including 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,
production, or other contractual commitments. Hedge accounting is applied only
if the derivative reduces the risk of the underlying hedge item, is designated
as a hedge at its inception, and is expected to result in financial impacts
which are inversely correlated to those of the item(s) being hedged. If
correlation ceases to exist, hedge accounting is terminated and mark-to-market
accounting is applied. Changes in market value of these transactions are
deferred until the gain or loss on the hedged item is recognized. If the hedged
item matures or is sold, the value of the derivative or other financial
instrument is recognized as a gain or loss in operating income in the
Consolidated Statements of Income. Cash inflows and outflows associated with
these price risk management activities are recognized in operating cash flow as
the settlements of transactions occur. See Note 4 for a further discussion of
the Company's price risk management activities.
 
  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
                                       40
<PAGE>   45
 
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.
 
     As a result of the Merger, EPTPC entered into a new tax sharing agreement
with Newport News Shipbuilding Inc., New Tenneco and EPG. 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 giving effect to the
Distributions, New Tenneco and Newport News Shipbuilding Inc. will be liable to
EPTPC 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, EPTPC paid New Tenneco
in 1997 for the tax benefits realized from the deduction of 1996 taxable losses
generated by a debt realignment in accordance with the Merger.
 
  Treasury Stock
 
     Treasury stock is accounted for using the cost method and is shown as a
reduction to stockholders' equity in the consolidated balance sheets. Treasury
stock sold or issued is valued on a first-in first-out basis. Included in
treasury stock at December 31, 1997, and 1996, were 680,000 shares of common
stock that were reserved to secure benefits under certain of the Company's
benefit plans.
 
  Stock-Based Compensation
 
     As allowed under SFAS No. 123, the Company has elected to continue to apply
the provisions of Accounting Principles Board Opinion No. 25 and related
interpretations in accounting for its stock compensation plans. The Company uses
fixed and variable plan accounting for fixed and variable
compensation plans, respectively. Accordingly, compensation expense is not
recognized for stock options unless the options were granted at a price lower
than market on the grant date.
 
  Capital Structure Reporting and Earnings Per Share
 
     The Company's capital structure is presented in accordance with the
Financial Accounting Standards Board SFAS No. 129, Disclosure of Information
about Capital Structure. Basic and diluted earnings per share are determined in
accordance with the guidelines established by the Financial Accounting Standards
Board's SFAS No. 128, Earnings Per Share. See Note 15 for Company's calculation
of basic and diluted earnings per share.
 
  Recent Pronouncements
 
  Comprehensive Income
 
     In June 1997, the Financial Accounting Standards Board issued SFAS No. 130,
Reporting Comprehensive Income, which establishes standards for reporting and
displaying comprehensive income and its components in a full set of
general-purpose financial statements. SFAS No. 130 requires that all items that
are required to be recognized under accounting standards as components of
comprehensive income be reported in a financial statement that is displayed with
the same prominence as other financial statements. This pronouncement is
effective for the financial statements for periods beginning after December 15,
1997. The Company is planning to adopt this statement in the first quarter of
1998.
 
  Segment Reporting
 
     In June 1997, the Financial Accounting Standards Board issued SFAS No. 131,
Disclosures about Segments of an Enterprise and Related Information, which
establishes the way that public business
 
                                       41
<PAGE>   46
 
enterprises report information about operating segments in annual and interim
financial statements issued to shareholders. It also establishes standards for
related disclosures about products and services, geographic areas, and major
customers. This pronouncement is effective for financial statements for periods
beginning after December 15, 1997. The Company is planning to adopt this
statement in the first quarter of 1998 and the number of reportable segments is
expected to increase.
 
  Pensions and Other Postretirement Benefits Disclosures
 
     In February 1998, SFAS No. 132, Employers' Disclosures about Pensions and
Other Postretirement Benefits, was issued by the Financial Accounting Standards
Board to standardize related disclosure requirements. SFAS No. 132 requires that
additional information be disclosed regarding changes in the benefit obligation
and fair values of plan assets, and eliminates certain disclosures no longer
considered useful, including general descriptions of the plans. Aggregation of
information about certain plans is also permitted. This statement does not
change the requirements for the measurement and recognition of those plans. It
is effective for fiscal years beginning after December 15, 1997. The Company is
currently evaluating the effect of this pronouncement.
 
  Other
 
     In 1997, the Company adopted or applied the relevant provisions of SFAS No.
123, Accounting for Stock-Based Compensation SFAS No. 125, Accounting for
Transfers and Servicing of Financial Assets and Extinguishment of Liabilities,
SFAS No. 127, Deferral of the Effective Date of Certain Provisions of FASB
Statement No. 125, SFAS No. 128, Earnings per Share, SFAS No. 129, Disclosure of
Information about Capital Structure, the Securities and Exchange Commission's
Financial Reporting Release No. 48, Disclosure of Derivative and Other Financial
Instruments and Statement of Position No. 96-1, Environmental Remediation
Liabilities. The adoption or application of these pronouncements did not have a
material impact on the Company's financial position or results of operations.
 
2. ACQUISITIONS
 
     In December 1997, the Company completed the purchase of gathering
facilities consisting of 360 miles of pipeline and a cryogenic gas processing
plant through the acquisition of 100 percent of the stock of PacifiCorp's Texas
Gulf Coast gathering and processing subsidiaries at a cash price of
approximately $195 million.
 
     In October 1997, the Company completed the acquisition of Gulf States Gas
Pipeline Company. The assets purchased include a 175-mile gathering and
intrastate transmission system in Northwest Louisiana with a capacity of 250
MMcf/d. The purchase price was approximately $39 million which included the
issuance of $21 million of common stock.
 
     On December 12, 1996, the Company completed the acquisition of EPTPC in a
transaction accounted for as a purchase. Accordingly, the purchase price has
been 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 total purchase price over historical
carrying amounts of the net assets acquired has been allocated to property,
plant and equipment of EPTPC's interstate pipeline systems. Such allocation was
confirmed by an independent appraisal of the property acquired, completed in
1997.
 
     In the Merger, which was in accordance with the Merger Agreement, Old
Tenneco changed its name to EPTPC. Prior to the Merger, Old Tenneco and its
subsidiaries completed various intercompany transfers and distributions which
restructured, divided and separated their businesses, assets and liabilities so
that all the assets, liabilities and operations related to the Industrial
Business and the Shipbuilding Business were spun-off to Old Tenneco's then
existing common stockholders. The Distributions were effected on December 11,
1996 pursuant to the Distribution Agreement dated as of November 1, 1996.
Following the Distributions, the remaining operations of Old Tenneco consisted
primarily of those operations related to the transmission and marketing of
natural gas. Results of operations of EPTPC were included in the Company's
Consolidated Statements of Income for the last 20 days of 1996.
                                       42
<PAGE>   47
 
     On October 30, 1996, the IRS issued a private letter ruling to Old Tenneco,
in which it ruled that for U.S. federal income tax purposes (i) the
Distributions would be tax-free to Old Tenneco and, except to the extent cash is
received in lieu of fractional shares, to its then existing stockholders, (ii)
the Merger would constitute a tax-free reorganization, and (iii) certain other
transactions effected in connection with the Merger and Distributions 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.
 
     The consideration paid by EPG in the Merger consisted of:
 
     - the retention after the Merger of approximately $2.6 billion of debt and
       preferred stock obligations of Old Tenneco, subject to certain
       adjustments (which consisted, in part, of (1) approximately $.2 billion
       of public debt of Old Tenneco outstanding at the effective time of the
       Merger, (2) $2.1 billion of debt of Old Tenneco outstanding at the
       effective time of the Merger under a $3 billion Revolving Credit and
       Competitive Advance Facility Agreement, dated as of November 4, 1996 (the
       "Credit Facility"), among Old Tenneco, certain banks and other financial
       institutions and The Chase Manhattan Bank, as agent), and (3) $300
       million of Old Tenneco preferred stock);
 
     - the issuance of 18.8 million shares of common stock of EPG valued at
       approximately $913 million, based on a closing price per share of common
       stock on the New York Stock Exchange of $48.625 on December 9, 1996, to
       Old Tenneco's then existing common and preferred stockholders; and
 
     - the retention of approximately $600 million of estimated assumed
       liabilities related to certain discontinued businesses of Old Tenneco.
 
     The number of shares of EPG's common stock issued in the Merger to
stockholders of Old Tenneco was determined pursuant to formulas set forth in the
Merger Agreement. In the Merger, (i) a holder of Old Tenneco's common stock
received .093 of a share of EPG's common stock for each share of Tenneco common
stock, (ii) a holder of Old Tenneco's $7.40 Cumulative Preferred Stock received
2.365 shares of EPG's common stock for each such share of $7.40 Cumulative
Preferred Stock, and (iii) a holder of Old Tenneco's $4.50 Cumulative Preferred
Stock received 2.365 shares of EPG's common stock for each such share of $4.50
Cumulative Preferred Stock.
 
     At the time of the Merger, EPG indirectly owned 100 percent of the common
equity and approximately 75 percent of the combined equity value of EPTPC. The
remaining 25 percent of the combined equity of EPTPC was comprised of $296
million of preferred stock issued in a public offering by Old Tenneco on
November 18, 1996, which remains outstanding.
 
     Assets acquired, liabilities assumed, and consideration received are as
follows:
 
<TABLE>
<S>                                                           <C>
Fair value of assets acquired...............................  $  6,649
Cash acquired...............................................       (75)
Liabilities assumed.........................................    (5,724)
Issuance of common stock....................................      (913)
                                                              --------
          Net cash consideration received...................  $    (63)
                                                              ========
</TABLE>
 
                                       43
<PAGE>   48
 
     The following unaudited pro forma information presents a summary of what
the consolidated results of operations would have been on a pro forma basis for
the years ended December 31, 1996 and 1995, assuming the EPTPC acquisition had
occurred January 1, 1995:
 
<TABLE>
<CAPTION>
                                                               1996        1995
                                                              ------      ------
                                                                (IN MILLIONS,
                                                                    EXCEPT
                                                              PER SHARE AMOUNTS)
<S>                                                           <C>         <C>
Operating revenue...........................................  $5,281      $2,912
Net income..................................................  $  183      $  167
Basic earnings per common share.............................  $ 3.22      $ 2.98
</TABLE>
 
     In December 1996, subsequent to the Merger, TGP sold 70 percent of its
interests in two natural gas pipeline systems in Australia to CNGI Australia
Pty. Limited, a wholly owned indirect subsidiary of Consolidated Natural Gas
Company, and four Australian investors for approximately $400 million, inclusive
of related debt financing, and completed the sale of its oil and gas
exploration, production and financing unit, formerly known as Tenneco Ventures,
in a $105 million transaction. After consideration of the purchase price
allocation adjustments, there was no gain or loss recognized on these
transactions.
 
     Effective June 1996, the Company acquired Cornerstone in a transaction
accounted for as a purchase. The purchase price of approximately $94 million,
exclusive of acquisition costs, was financed through internally generated funds
and short-term borrowings. Acquisition costs of approximately $5 million were
capitalized. The cost of the acquisition was allocated on the basis of the
estimated fair value of the assets acquired and the liabilities assumed,
resulting in goodwill of approximately $59 million which is being amortized over
40 years using the straight-line method. Results of operations of Cornerstone
are included in the Company's Consolidated Statements of Income for the period
June 1996 through December 1996.
 
     Effective September 1995, the Company acquired Eastex Energy Inc., and in
December 1995, the Company acquired all of the issued and outstanding capital
stock of Premier. Effective July 1996, the name Eastex Energy Inc. was changed
to, and its subsidiaries were merged into, EPEM. Results of operations of Eastex
Energy Inc. and Premier are included in the Company's Consolidated Statement of
Income for the periods after their acquisition.
 
3. FINANCING TRANSACTIONS
 
     The Company had short-term borrowings, including current maturities of
long-term debt, at December 31, 1997 and December 31, 1996, as follows:
 
<TABLE>
<CAPTION>
                                                              1997    1996
                                                              ----    ----
<S>                                                           <C>     <C>
EPG Revolving Credit Facility...............................  $ 45    $ 17
EPG Revolving Credit Facility with TGP designated as
  borrower..................................................   417      --
Commercial paper............................................   326      --
Other credit facilities.....................................    25      --
Current maturities of EPTPC Revolving Credit Facility.......    --     700
Current maturities of other long-term debt..................    72     124
                                                              ----    ----
                                                              $885    $841
                                                              ====    ====
</TABLE>
 
                                       44
<PAGE>   49
 
     Long-term debt outstanding at December 31, 1997 and 1996, consisted of the
following:
 
<TABLE>
<CAPTION>
                                                               1997       1996
                                                              ------     ------
                                                                (IN MILLIONS)
<S>                                                           <C>        <C>
Long-term debt
  EPG
     Debentures due 2012 through 2026, average effective
      interest rates of 8.3% in 1997 and 8.2% in 1996.......  $  475     $  475
     Notes due 1997 and 2003, average effective interest
      rates of 7.6% in 1997 and 7.4% in 1996................     462        562
  EPTPC
     Credit Facility due 1999, average effective interest
      rate of 5.9% in 1997 and 6.8% from the Merger date to
      December 31, 1996.....................................      --      1,600
     Debentures due 2008 through 2025, average effective
      interest rate of 7.2% in 1997 and 7.4% from the Merger
      date to December 31, 1996.............................      55         55
     Notes due 1998 through 2005, average effective interest
      rate of 6.4% in 1997 and 6.3% from the Merger date to
      December 31, 1996.....................................      87         90
  TGP
     Debentures due 2011, average effective interest rate of
      7.9% in 1997 and 7.5% from the Merger date to December
      31, 1996..............................................      75         74
     Debentures due 2017, average effective interest rate of
      7.8% in 1997..........................................     295         --
     Debentures due 2027, average effective interest rate of
      7.2% in 1997..........................................     296         --
     Debentures due 2037, average effective interest rate of
      7.9% in 1997..........................................     293         --
  EPECC
     Senior notes due 1997 and 2001, average effective
      interest rate of 6.0% in 1997 and 6.3% from the Merger
      date to December 31, 1996.............................      15         30
     Subordinated notes due 1998, average effective interest
      rate of 6.5% in 1997 and 6.2% from the Merger date to
      December 31, 1996.....................................       7          7
  MPC
     Project financing loan, due March 2007, average
      effective interest rates of 9.4% in 1997 and 8.9% in
      1996..................................................     126        135
  Other Subsidiaries
     Notes due 1997 through 2014, average effective interest
      rate of 8.7% in 1997 and 7.9% in 1996.................       5         11
                                                              ------     ------
                                                               2,191      3,039
  Less current maturities...................................      72        824
                                                              ------     ------
          Total long-term debt..............................  $2,119     $2,215
                                                              ======     ======
</TABLE>
 
     The following are aggregate maturities of long-term debt for the next 5
years and in total thereafter:
 
<TABLE>
<CAPTION>
                                                              (IN MILLIONS)
                                                              -------------
<S>                                                           <C>
1998........................................................     $   72
1999........................................................         63
2000........................................................         18
2001........................................................         53
2002........................................................        241
Thereafter..................................................      1,744
                                                                 ------
          Total long-term debt, including current
           maturities.......................................     $2,191
                                                                 ======
</TABLE>
 
                                       45
<PAGE>   50
 
  Other Financing Arrangements
 
     During 1997, EPECC's 10.725% Senior Notes for $15 million and EPG's 6.90%
Notes for $100 million matured and were retired. In addition, the MPC made debt
payments totaling approximately $9 million.
 
     In February 1997, EPG issued an additional 3 million shares of common
stock. Proceeds of approximately $152 million, net of issuance costs, were used
to repay a portion of EPTPC's credit facility and for general corporate
purposes.
 
     At December 31, 1996, EPTPC had an additional $900 million outstanding
under its credit facility which was reflected as long-term debt because it was
expected to be refinanced with long-term debt during the first quarter of 1997.
In March 1997, TGP issued $300 million aggregate principal of 7 1/2% debentures
due 2017, $300 million aggregate principal of 7% debentures due 2027, and $300
million aggregate principal 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, EPG established a new $750 million 5-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"). Initially, the interest rate will be a 32.5 basis point
spread over LIBOR and the spread will vary based on EPG's long-term debt credit
rating. This facility replaced EPG's $750 million five-year revolving credit
facility and $250 million 364-day revolving credit facility which were
established in November 1996. 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
5-year portion of the new Revolving Credit Facility with TGP designated as the
borrower. The remainder of the availability under the Revolving Credit Facility
is expected to be used for general corporate purposes including, but not limited
to, backstopping EPG's $1 billion commercial paper program. The availability of
borrowings under the Company's credit facilities is subject to certain specified
conditions, which management believes it currently meets. In June 1997, the
Company established a non-committed short-term facility with a U.S. financial
institution.
 
     In December 1997, EPG filed a shelf registration statement pursuant to
which EPG may offer up to $900 million (including $250 million transferred from
prior shelf registrations) of common or preferred equities, various forms of
debt securities (including convertible debt securities), and various types of
trust securities from time to time as determined by market conditions. In March
1998, the El Paso Energy Capital Trust I, a Delaware business trust sponsored by
the Company, issued 6.5 million 4 3/4% trust convertible preferred securities.
The sole assets of the trust are approximately $335 million principal amount of
4 3/4% convertible subordinated debentures due 2028 of the Company. As a result
of such offering, EPG has approximately $565 million of capacity remaining under
its shelf registrations to issue public securities registered thereunder. In
addition, TGP has approximately $100 million remaining on its February 1997
shelf registration.
 
     In March 1998, EPG retired its outstanding 8 5/8% debentures in the amount
of $16.8 million.
 
     The Company must comply with various restrictive covenants contained in its
debt agreements which include, among others, maintaining a consolidated debt and
guarantees to capitalization ratio no greater than 70 percent. In addition, the
Company's subsidiaries on a consolidated basis (as defined in the agreements)
may not incur debt obligations which would exceed $300 million in the aggregate,
excluding acquisition debt, project financing, and certain refinancings. As of
December 31, 1997, EPG's consolidated debt and guarantees to capitalization
ratio (as defined in the agreement) was 58 percent and debt obligations of EPG
subsidiaries in excess of permitted debt did not exceed $300 million on a
consolidated basis.
 
                                       46
<PAGE>   51
 
4. FINANCIAL INSTRUMENTS
 
  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, 1997, and 1996, 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 the long-term debt has been estimated based on
quoted market prices for the same or similar issues. The project financing debt
is at market interest rates and therefore, the fair value of the project
financing debt is represented by the carrying amount. The fair value of all
derivative financial instruments is the estimated amount at which management
believes they 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 following table reflects the carrying amount and estimated fair value
of the Company's financial instruments at December 31:
 
<TABLE>
<CAPTION>
                                                               1997                     1996
                                                       ---------------------    ---------------------
                                                       CARRYING                 CARRYING
                                                        AMOUNT    FAIR VALUE     AMOUNT    FAIR VALUE
                                                       --------   ----------    --------   ----------
                                                                       (IN MILLIONS)
<S>                                                    <C>        <C>           <C>        <C>
Balance sheet financial instruments:
  Long-term debt, excluding project financing........   $2,065      $2,208       $2,904      $2,936
  Project financing debt.............................      126         126          135         135
Other financial instruments:
  Trading
     Futures contracts...............................       (3)         (3)          25          25
     Option contracts................................        3           3           --          --
     Swap and forwards contracts.....................       23          23           14          14
  Non-Trading
     Interest rate swap agreements...................       --          (9)          --         (10)
     Equity swap.....................................        6           8           --          --
     Futures contracts...............................       --          --           --           2
     Option contracts................................       --           1           --          --
     Swap and forwards contracts.....................       --           4           --          --
</TABLE>
 
  Trading Commodity Activities
 
     The Company, through its merchant services business, offers integrated
price risk management services for trading purposes to the energy sector. These
services primarily relate to energy related commodities including natural gas,
power, NGLs, refined products and crude oil. The Company provides these services
through a variety of financial instruments 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. The Company recognized gross margin of $17
million and $28 million during 1997 and 1996, respectively, arising from its
trading activities.
 
                                       47
<PAGE>   52
 
     The fair value of the financial instruments as of December 31, 1997, and
the average fair value of those instruments held during the year are set forth
below (amounts in millions):
 
<TABLE>
<CAPTION>
                                                                                AVERAGE FAIR
                                                                                VALUE FOR THE
                                                                                 YEAR ENDED
                                                       ASSETS    LIABILITIES     12/31/97(A)
                                                       ------    -----------    -------------
<S>                                                    <C>       <C>            <C>
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.
 
     The fair value of the financial instruments as of December 31, 1996, and
the average fair value of those instruments held during the year are set forth
below (amounts in millions):
 
<TABLE>
<CAPTION>
                                                                                AVERAGE FAIR
                                                                                VALUE FOR THE
                                                                                 YEAR ENDED
                                                       ASSETS    LIABILITIES     12/31/96(A)
                                                       ------    -----------    -------------
<S>                                                    <C>       <C>            <C>
Futures contracts....................................   $25          $--            $  4
Option contracts.....................................    10           10             (11)
Swap and forward contracts...........................    68           54               7
</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, 1997 are set forth below (natural gas and petroleum volumes in trillions of
British thermal unit equivalents, power volumes in millions of megawatt hours):
 
<TABLE>
<CAPTION>
                                                 FIXED PRICE    FIXED PRICE       MAXIMUM
                                                    PAYOR        RECEIVER      TERMS IN YEARS
                                                 -----------    -----------    --------------
<S>                                              <C>            <C>            <C>
Energy Commodities
  Natural gas..................................     4,079         3,584              20
  Power........................................        12            13               1
  Petroleum products...........................       197           195               2
</TABLE>
 
     The notional amounts and terms of these financial instruments at December
31, 1996 are set forth below (natural gas and petroleum volumes in trillions of
British thermal units equivalent, power volumes in millions of megawatt hours):
 
<TABLE>
<CAPTION>
                                                 FIXED PRICE    FIXED PRICE       MAXIMUM
                                                    PAYOR        RECEIVER      TERMS IN YEARS
                                                 -----------    -----------    --------------
<S>                                              <C>            <C>            <C>
Energy Commodities:
  Natural gas..................................      914            873               5
  Power........................................        1              1               1
  Petroleum products...........................       58             77               1
</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 in the markets at any time based on the
Company's risk management needs and liquidity of the commodity market.
 
     The volumetric weighted average maturity of the Company's entire portfolio
of price risk management activities as of December 31, 1997, was approximately
two years.
                                       48
<PAGE>   53
 
  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 group operating separately from the units that
create or actively manage these risk exposures to ensure compliance with the
Company's stated risk management policies.
 
     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 counterparties associated with the Company's assets
from price risk management activities as of December 31, 1997 are summarized as
follows (amounts in millions):
 
<TABLE>
<CAPTION>
                                                 ASSETS FROM PRICE RISK MANAGEMENT ACTIVITIES
                                                           AS OF DECEMBER 31, 1997
                                               ------------------------------------------------
                                                                           BELOW
                                               INVESTMENT GRADE(a)    INVESTMENT GRADE    TOTAL
                                               -------------------    ----------------    -----
<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.
 
     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.
 
     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 and the use of standardized agreements
which allow for the netting of positive and negative exposures associated with a
single counterparty.
 
  Other Price Risk Management Activities
 
     MPC has entered into interest rate swap agreements which effectively
converts $114.3 million of floating-rate debt to fixed-rate debt (see Note 3,
Long-Term Debt and Other Financing). MPC makes payments to counterparties at
fixed rates and in return receives payments at floating rates. The two swap
agreements were entered into in March 1992 and have remaining terms of
approximately 2 years and 4 years, respectively. This transaction is recorded
using hedge accounting.
 
     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
 
                                       49
<PAGE>   54
 
18.5 percent of CAPSA's then outstanding stock. Under the swap, the Company pays
interest, 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
is two years, but may be extended to five years with consent of the parties.
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.
 
     In February 1995, EPNC entered into a 7.75-year lease agreement for the
Chaco Plant (see Note 5, Commitments and Contingencies). To moderate the
exposure to interest rate changes, EPNC entered into an interest rate swap
arrangement effective July 31, 1995, whereby approximately 50 percent of the
current lease financing was converted from LIBOR based floating rate to a 5.9
percent fixed rate. This agreement expired December 31, 1997.
 
     The effective dates and notional amounts subject to the swap arrangement
were as follows:
 
<TABLE>
<CAPTION>
                                                              (IN MILLIONS)
                                                              -------------
<S>                                                           <C>
July 31, 1995 -- October 31, 1995...........................       $13
October 31, 1995 -- April 30, 1996..........................       $25
April 30, 1996 -- December 31, 1997.........................       $35
</TABLE>
 
     The primary risks associated with interest rate swaps are the exposure to
movements in interest rates and the ability of the counterparties to meet the
terms of the contracts. Based on review and assessment of counterparty risk,
neither MPC nor EPNC anticipates non-performance by the other parties.
 
5. COMMITMENTS AND CONTINGENCIES
 
  Indonesian Economic Difficulties
 
     The Company owns a 47.5 percent interest in a power generating plant in
Sengkang, South Sulawesi, Indonesia, with a book value at December 31, 1997 of
approximately $19 million. Recent economic events in Indonesia have resulted in
the devaluation of the Indonesian Rupiah and delays or cancellations of certain
infrastructure power projects in that country. The Company has met with PLN and
the Indonesian Minister of Finance to discuss the terms of its power sales
agreement in light of the economic problems. While the Company cannot predict
the ultimate outcome of Indonesia's financial difficulties or the impact of such
matters to Company, it believes the PLN, with the backing of the Office of the
Minister of Finance, will honor all current invoices on the Sengkang project in
full and therefore, the current economic difficulties in Indonesia will not have
a material adverse effect on the Company's financial position or results of
operations.
 
  Rates and Regulatory Matters
 
     TGP -- In February 1997, TGP filed with FERC a settlement of all issues
related to the recovery by TGP of its GSR and other transition costs and related
proceedings (the "GSR Stipulation and Agreement"). In April 1997, FERC approved
the settlement and TGP implemented the settlement on May 1, 1997. Under the
terms of the GSR Stipulation and Agreement, TGP is entitled to collect from
customers up to $770 million, of which approximately $682 million has been
collected as of December 31, 1997. TGP is entitled to recover additional
transition costs, up to the remaining $88 million, through a demand
transportation surcharge and an interruptible transportation surcharge. The
demand transportation surcharge portion is scheduled to be recovered over a
period extending through December 1998. 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.
 
                                       50
<PAGE>   55
 
\In December 1994, TGP filed for a general rate increase with FERC and in April
1996, it filed 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. In October 1996, FERC
approved the stipulation with certain modifications and clarifications which are
not material. In January 1997, FERC issued an order denying requests for
rehearing of that order. 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 had provided a reserve for these rate refunds as
revenues were collected. One party, a competitor of TGP, filed with the Court of
Appeals a Petition for Review of the FERC orders.
 
     In July 1997, FERC issued an order on rehearing of its July 1996 order
addressing cost allocation and rate design issues of TGP's 1991 general rate
proceeding. All cost of service issues were previously resolved pursuant to a
settlement that was approved by FERC. In the July 1996 order, FERC remanded to
the presiding ALJ the issue of proper allocation of TGP's New England lateral
costs. In the July 1997 order on rehearing, FERC clarified, among other things,
that although the ultimate resolution as to the proper allocation of costs will
be applied retroactively to July 1, 1995, the cost of service settlement does
not allow TGP to recover from other customers amounts that TGP may ultimately be
required to refund. TGP has filed with the Court of Appeals a Petition for
Review of the FERC orders on this issue. In December 1997, the ALJ issued his
decision on the proper allocation of the New England lateral costs. The decision
adopts a methodology that economically approximates TGP's current methodology.
The ALJ's decision is pending before FERC.
 
     In October 1997, TGP filed its cashout report for the period September 1995
through August 1996. TGP previously filed cashout reports for the period
September 1993 through August 1995. TGP's October 1997 filing showed a
cumulative loss of $11 million that would be rolled forward to the next cashout
period pursuant to its tariff. FERC has requested additional information and
justification from TGP as to its cashout methodology and reports. TGP's cashout
methodology and reports are currently pending before FERC.
 
     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 three 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, 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.
 
     EPG -- In June 1995, EPG filed with FERC for approval of new system rates
for mainline transportation to be effective January 1, 1996. In March 1996, EPG
filed a comprehensive offer of settlement to resolve that proceeding as well as
issues surrounding certain contract reductions and expirations that were to
occur from January 1, 1996 through December 31, 1997. In April 1997, FERC
approved EPG's settlement as filed and determined that only the contesting
party, Edison, should be severed for separate determination of the rate it
ultimately pays EPG. Hearings to determine Edison's rates are scheduled to begin
in April 1998. Pending the outcome of those hearings, Edison continues to pay
the filed rates, subject to refund, and EPG continues to provide a reserve for
such potential refunds. In July 1997, FERC issued an order denying the requests
for rehearing of the April 1997 order and the settlement was implemented
effective July 1, 1997. Edison and GPM Corporation, a competitor of EPG, have
filed with the Court of Appeals separate petitions for review of FERC's April
1997 and July 1997 orders.
 
     The rate settlement establishes, among other things, base rates through
December 31, 2005. Such rates escalate annually beginning in 1998. In addition,
the settlement provides for settling customers (i) to pay $295 million
(including interest) as a risk sharing obligation, which approximates 35 percent
of anticipated revenue shortfalls over an 8 year period, resulting from the
contract reductions and expirations referred to
 
                                       51
<PAGE>   56
 
above, (ii) to receive 35 percent of additional revenues received by EPG, above
a threshold, for the same eight-year period, and (iii) to have the base rates
increase or decrease if certain changes in laws or regulations results in
increased or decreased costs in excess of $10 million a year. In accordance with
the terms of the rate settlement, EPG's refund obligation (including interest)
was approximately $194 million. EPG refunded $61 million to customers in August
1997, and in accordance with certain customers elections, the remaining $133
million of refund obligation was applied towards their $295 million risk sharing
obligation. An additional $75 million of the obligation was paid to EPG in
August 1997 and the $87 million balance, including interest, will be collected
by the end of 2003. At December 31, 1997 the remaining unearned balance of the
risk sharing amount collected was $189 million which will be recognized in
earnings ratably through 2003.
 
     The contract reductions and expirations referred to above resulted in EPG's
having, as of January 1, 1998, approximately 1.6 Bcf/d (or 34 percent) less of
total capacity committed under contracts requiring the payment of full tariff
reservation rates. Effective January 1, 1998, this uncommitted capacity had an
annual value, at full tariff reservation rates, of approximately $171 million.
 
     EPG has substantially offset the effects of these reductions in firm
capacity commitments through the rate settlement provisions referred to above,
by implementing cost control programs, and by actively seeking new markets, and
pursuing attractive opportunities to increase traditional market share. The new
markets EPG has targeted include various natural gas users in California which
were served indirectly through SoCal and PG&E, as well as new markets off the
east end of its system. In addition to other arrangements, in October 1997, EPG
entered into three contracts with NGC for the sale of all of its firm capacity
available as of January 1, 1998 to California (approximately 1.3 Bcf) for a
two-year period beginning January 1, 1998 at rates negotiated pursuant to EPG's
tariff provisions and FERC policies. EPG anticipates realizing at least $70
million in revenues (which will be subject to the revenue sharing provisions of
the rate settlement) under these contracts over the two-year period. The
contracts have a transport-or-pay provision requiring NGC to pay a minimum
charge equal to the reservation component of the contractual charge on at least
50 percent of the contracted volumes in each month in 1998 and on at least 72
percent of the contracted volumes each month in 1999. In December 1997, EPG made
a tariff filing to implement several negotiated rate contracts, including those
with NGC. In a protest to this filing made in January 1998, three shippers
(producers/marketers) requested FERC to require EPG to eliminate certain
provisions from the NGC contracts, to publicly disclose and repost the contracts
for competitive bidding, and to suspend their effectiveness. In an order issued
in January 1998, FERC rejected several of the arguments made in the protest and
allowed the contracts to become effective as of January 1, 1998 subject to
refund and to the outcome of a technical conference, which was held in March
1998. The technical conference addressed the operation of certain of the
contracts' provisions, including those which provide for crediting (to amounts
otherwise due under the contracts) of certain interruptible revenues which might
be received by EPG, and the protesters' claims that the contracts are
anti-competitive. Following written submissions by the parties, FERC will decide
what action to take. Assuming FERC allows the contracts to remain in effect, it
cannot be predicted at this time whether EPG will be able to remarket this
capacity after 1999 or the terms under which it may be remarketed.
 
     Under FERC procedures, take-or-pay cost recovery filings may be challenged
by pipeline customers on prudence and certain other grounds. Certain parties
sought review in the Court of Appeals of FERC's determination in the October
1992 order that certain buy-down/buy-out costs were eligible for recovery. In
January 1996, the Court of Appeals remanded the order to FERC with direction to
clarify the basis for its decision that the take-or-pay buy-down/buy-out costs
were eligible for recovery. In March 1997, following a technical conference and
the submission of statements of position and replies, FERC issued an order
determining that the costs related to all but one of EPG's disputed contracts
were eligible for recovery. The costs ruled ineligible for recovery totaled
approximately $3 million, including interest, and were refunded to customers in
the second quarter of 1997. In October 1997, FERC issued an order denying the
challenging parties' request for rehearing of the March 1997 order in most
respects, but determined that the costs incurred pursuant to two additional EPG
contracts were ineligible for recovery. These costs, including interest, totaled
approximately $9 million, and were refunded to customers in February 1998. The
challenging parties, which
 
                                       52
<PAGE>   57
 
claim that EPG should be required to refund up to an additional $31 million,
excluding interest, have filed a petition for review of the FERC order in the
Court of Appeals.
 
     In an order issued in April 1997 in the proceeding involving the spin down
of EPG's gathering facilities to EPFS, FERC found that EPG acted appropriately
in not including its Chaco Station in the facilities to be transferred to EPFS,
and that the Chaco Station had been correctly functionalized by EPG as a
transmission facility. Requests for rehearing of this order were filed by
Williams Field Services Group and
GPM Corporation. In a November 1997 order, FERC revised its previous decision
and found that the Chaco Station is a gathering facility. EPG and others have
sought rehearing of this order, and the matter is still pending.
 
     Separately, in November 1996, GPM Corporation filed a complaint, as
amended, with FERC alleging that EPG's South Carlsbad compression facilities
were gathering facilities and were improperly functionalized by EPG as
transmission facilities. In a November 1997 order, FERC concluded that the South
Carlsbad Compressor Station performed a gathering function and directed EPG to
transfer the facility to EPFS. FERC held, however, that its November 1997
rulings would not affect the base settlement rates provided for under the 1996
rate settlement described above. EPG and others have sought rehearing of this
Order, and the matter is still pending.
 
     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 or results of
operations.
 
  Environmental Matters
 
     As of December 31, 1997, the Company had a reserve of approximately $284
million to cover environmental assessments and remediation activities discussed
below.
 
     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, in order 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, 1997, a
balance of $27 million remains to be collected under this agreement.
 
     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 33 sites under 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, 1997, the Company has estimated its share of the remediation costs at these
sites to be between $68 million and $83 million and has provided reserves that
it believes are adequate for such costs. Because 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 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
 
                                       53
<PAGE>   58
 
Superfund sites referenced above will not have a material adverse effect on the
Company's financial position or results of operations.
 
     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 their
initial stages and accordingly, it is not 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.
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.
 
  Legal Proceedings
 
     See Item 3, Legal Proceedings, which is incorporated herein by reference.
 
  Year 2000
 
     The Company has established an executive steering committee and a project
team to coordinate the assessment, remediation, testing and implementation of
the necessary modifications to its key computer applications (which consist of
internally developed computer applications, third party software, hardware and
embedded chip systems) to assure that such systems and related processes will
remain functional.
 
     The assessment phase related to internally developed computer applications
has been completed and the costs estimate for making the necessary changes to
such systems, including implementation and testing efforts, is approximately $8
million to be spent in 1998 and 1999. These estimates were based on various
factors including availability of internal and external resources and complexity
of the software applications. The recent upgrade of various systems,
particularly the financial systems, to a Year 2000 compliant client/server
platform have greatly reduced or eliminated concerns in those areas.
 
     The assessment phase for the third party software and hardware impacts is
continuing, with completion of that phase and an estimate of costs necessary to
modify or replace those systems to be available in the second quarter of 1998.
Included in this phase of the project is the effort to obtain representations
and assurances from third party vendors that their software and hardware
products being used by the Company are or will be Year 2000 compliant.
Implementation and testing phases are expected to be completed by mid 1999.
 
     It is the Company's goal to ensure that all of the critical systems and
processes which are under its direct control remain functional. However, because
certain systems may be interrelated with systems outside the control of the
Company, there can be no assurance that all implementations will be successful.
Management does not expect the costs to modify its systems or to correct any
unsuccessful system implementations to have a material adverse impact on the
Company's financial position or results of operations.
 
                                       54
<PAGE>   59
 
  Operating Leases
 
     The Company leases certain property, facilities and equipment under various
operating leases. In addition, in 1995, 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. EPG unconditionally guaranteed all obligations of EPNC under the
lease.
 
     Minimum annual rental commitments at December 31, 1997, were as follows:
 
<TABLE>
<CAPTION>
                        YEAR ENDING
                        DECEMBER 31,                           OPERATING LEASES
------------------------------------------------------------   ----------------
                                                               (IN MILLIONS)
<S>                                                            <C>
   1998.....................................................         $ 19
   1999.....................................................           18
   2000.....................................................           17
   2001.....................................................           17
   2002.....................................................           13
   Thereafter...............................................           68
                                                                     ----
          Total.............................................         $152
                                                                     ====
</TABLE>
 
     Aggregate minimum commitments have not been reduced by minimum sublease
rentals of approximately $15 million due in the future under noncancelable
subleases.
 
     Rental expense for operating leases for 1997, 1996, and 1995 was $23
million, $14 million, and $9 million, respectively.
 
  Guarantees
 
     In addition to its guaranty of EPNC's obligations under the Chaco Plant
lease, EPG has also unconditionally guaranteed all obligations of EPED Sam
Holdings Company, an indirect subsidiary of EPEI, which obligations are not
expected to exceed $51 million in connection with its share of the financing for
the Samalayuca Power Plant project. In addition, EPG has issued guarantees up to
$50 million related to its subsidiaries participation in the development of an
electric generation facility in Agawam, Massachusetts. EPG has unconditionally
guaranteed the obligations of certain other subsidiaries, which are not expected
to exceed $18 million, in connection with the Coyote Gulch natural gas treating
plant and the TransColorado Pipeline Project.
 
     During 1997, in connection with its international development activities,
the Company issued a number of parent guarantees including $100 million relating
to the CAPSA acquisition, $43 million relating to the Bolivia to Brazil pipeline
project, $16 million relating to the EMA Power project, and a balance of $10
million for various other projects. Also, the Company issued $33 million in
letters of credit with $24 million for the Manuas Power project and the balance
for various other projects.
 
  Capital Commitments
 
     At December 31, 1997, the Company had capital or investment commitments of
$254 million, which are expected to be funded through cash provided by
operations 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.
 
                                       55
<PAGE>   60
 
  Purchase Obligations
 
     In connection with the financing commitments of certain joint ventures, TGP
has entered into unconditional purchase obligations for products and services
totaling $99 million at December 31, 1997. TGP's annual obligations under these
agreements are $22 million for the year 1998, $21 million for the years 1999 and
2000, $11 million for the year 2001, $4 million for the year 2002, and $20
million thereafter. Payments under such obligations, including additional
purchases in excess of contractual obligations, were $26 million, $25 million
and $26 million for the years 1997, 1996 and 1995, respectively. Prior to August
1997, TGP had an obligation to purchase 30 percent of the output of the Great
Plains coal gasification project's original design capacity through July 2009.
TGP has executed a settlement of this contract as a 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.
 
     Management is not aware of other commitments or contingent liabilities
which would have a materially adverse effect on the Company's financial
condition or results of operations.
 
6. INCOME TAXES
 
     The following table reflects the components of income tax expense for the
years ended December 31:
 
<TABLE>
<CAPTION>
                                                              1997     1996     1995
                                                              ----     ----     ----
                                                                  (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
Current
  Federal...................................................  $(45)    $23      $13
  State.....................................................   (21)      7        5
                                                              ----     ---      ---
                                                               (66)     30       18
                                                              ----     ---      ---
Deferred
  Federal...................................................   164      (4)      31
  State.....................................................    31      (1)      (1)
                                                              ----     ---      ---
                                                               195      (5)      30
                                                              ----     ---      ---
          Total tax expense.................................  $129     $25      $48
                                                              ====     ===      ===
</TABLE>
 
     The following table reflects the components of the net deferred tax
liabilities at December 31:
 
<TABLE>
<CAPTION>
                                                               1997      1996
                                                              ------    ------
                                                               (IN MILLIONS)
<S>                                                           <C>       <C>
Deferred tax liabilities
  Property, plant, and equipment............................  $1,795    $1,395
  Regulatory and other assets...............................     336       274
                                                              ------    ------
          Total deferred tax liability......................   2,131     1,669
                                                              ------    ------
Deferred tax assets
  U.S. net operating loss carryover.........................     111        10
  Accrual for regulatory issues.............................     118        76
  Postretirement benefits...................................     122       124
  Other liabilities.........................................     405       503
  Other.....................................................       1         5
  Valuation allowance.......................................      (8)       --
                                                              ------    ------
          Total deferred tax asset..........................     749       718
                                                              ------    ------
Net deferred tax liability..................................  $1,382    $  951
                                                              ======    ======
</TABLE>
 
                                       56
<PAGE>   61
 
     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>
                                                               1997   1996   1995
                                                               ----   ----   ----
                                                                 (IN MILLIONS)
<S>                                                            <C>    <C>    <C>
Tax expense at the statutory federal rate of 35%............   $119   $22    $47
Increase (decrease)
  State income tax, net of federal income tax benefit.......      7     4      2
  Other.....................................................      3    (1)    (1)
                                                               ----   ---    ---
Income tax expense..........................................   $129   $25    $48
                                                               ====   ===    ===
Effective tax rate..........................................    38%   39%    36%
                                                               ====   ===    ===
</TABLE>
 
     The cumulative undistributed earnings of certain foreign subsidiaries and
foreign corporate joint ventures were approximately $6 million as of December
31, 1997. 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. 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.
 
     The tax benefit associated with the exercise of nonstatutory stock options
reduced taxes payable by $11 million in 1997. Such benefits are included in
additional paid-in capital in the Consolidated Balance Sheet.
 
     As of December 31, 1997, approximately $1 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, 1997, approximately $1 million of general business credit and
$319 million of net operating loss carryovers were available to offset future
tax liabilities. The general business credit carryovers expire in the years 1998
through 2000. Approximately $263 million of the net operating loss carryovers
expire in 2012 and the remaining $56 million expires in the years 2002 through
2011. Usage of these carryovers are subject to the limitations provided for
under Section 382 of the IRS Code as well as the separate return limitation year
rules of IRS 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. Approximately $7 million 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.
 
     EPG and EPTPC each file a separate consolidated federal income tax return
which includes the operations of their respective subsidiaries as they existed
at the time of the Merger. Deferred taxes corresponding to the allocation of the
purchase price to the assets and liabilities acquired, have been reflected in
the Consolidated Balance Sheets at December 31, 1997, and 1996.
 
7. CAPITAL STOCK
 
  Common Stock
 
     In October 1997, approximately .4 million shares of common stock were
issued in connection with the acquisition of Gulf States Gas Pipeline Company.
Such shares were valued at approximately $21 million.
 
     In February 1997, approximately 3 million shares of common stock were
issued in a public offering registered under the Securities Act of 1933.
Proceeds of $152 million, net of issuance costs, were received and used to repay
borrowings under the Revolving Credit Facility.
 
                                       57
<PAGE>   62
 
     In December 1996, 18.8 million shares of EPG common stock were issued in
connection with the acquisition of EPTPC. Such shares were valued at
approximately $913 million.
 
  Treasury Stock
 
     From time to time, the Board has authorized the repurchase of EPG's
outstanding shares of common stock to be used in connection with EPG employee
stock-based compensation plans and for other corporate purposes. As of December
31, 1997, and 1996, EPG held 1,473,416 and 1,451,922 shares of treasury stock,
respectively. Included in the balance at December 31, 1997, were 680,000 shares
of treasury stock used to secure benefits under certain of the Company's benefit
plans which are subject to certain restrictions.
 
  Stock Dividend
 
     In January 1998, the Board declared a two-for-one stock split in the form
of a 100 percent stock dividend (on a per share basis). In March 1998, the
stockholders approved an increase in the Company's authorized common stock. The
proposed stock dividend will be paid on April 1, 1998 to stockholders of record
on March 13, 1998. Had the stock dividend been effective at December 31, 1997
and 1996, the number of shares outstanding would have been 122,581,816 and
113,453,468 at a par value of $368 million and $340 million, respectively.
 
     All presentations herein are made on a pre-split basis.
 
  Other
 
     EPG has 25,000,000 shares of authorized preferred stock, par value $0.01
per share, none of which have been issued, but of which 1,375,000 shares have
been designated as Series A Participating Preferred Stock and reserved for
issuance pursuant to the Company's preferred stock purchase rights plan.
 
8. STOCK-BASED COMPENSATION
 
     During 1997, 1996, and 1995 the Company granted stock options under various
stock option plans (the "Plans"). The Company applies Accounting Principles
Board Opinion No. 25 and related Interpretations in accounting for the Plans. In
1995, the Financial Accounting Standards Board issued SFAS No. 123, Accounting
for Stock-Based Compensation which, if fully adopted, changes the methods the
Company applies in recognizing the cost of the stock option plans. Adoption of
the cost recognition provisions of SFAS No. 123 was optional and the Company
elected not to apply provisions of SFAS No. 123. However, pro forma disclosures
as if the Company adopted the cost recognition provisions of SFAS No. 123 are
presented below.
 
     Under the stock option plans, the Company is authorized to issue shares of
Common Stock to employees and nonemployee directors pursuant to awards granted
as incentive stock options (intended to qualify under Section 422 of the
Internal Revenue Code of 1986, as amended), nonqualified stock options,
restricted shares, and stock appreciation rights.
 
  Nonqualified Stock Options
 
     The Company granted nonqualified stock options in 1997, 1996, and 1995
under its stock option plans. The stock options granted during these periods
have contractual terms of 10 years and either vest immediately or after
completion of one to five years of continuous employment from the grant date.
Options are also granted to nonemployee members of the Board at fair market
value on the date of grant and are exercisable immediately. Under the terms of
certain plans, EPG may grant SARs to certain holders of stock options. SARs are
subject to the same terms and conditions as the related stock options. As of
December 31, 1997, 25,269 SARs were outstanding which have been included in
stock options as part of tandem awards. The stock option holder who has been
granted tandem SARs can elect to exercise either an option or a SAR. SARs
entitle an option holder to receive a payment equal to the difference between
the option price and the fair market value of the common stock of EPG at the
date of exercise of the SAR. To the extent a SAR is exercised, the related
option is canceled, and to the extent an option is exercised, the related SAR is
canceled. Currently, the SARs are being accounted for as compensation expense
under Accounting Principles Board
                                       58
<PAGE>   63
 
Opinion No. 25 and are not considered for purposes of computing fair value of
outstanding options using the Black-Scholes option pricing model as described
below.
 
     A summary of the status of the Company's stock options as of December 31,
1997, 1996, and 1995 is presented below:
 
<TABLE>
<CAPTION>
                                                                   STOCK OPTIONS
                                      ------------------------------------------------------------------------
                                               1997                     1996                     1995
                                      ----------------------   ----------------------   ----------------------
                                                    WEIGHTED                 WEIGHTED                 WEIGHTED
                                      # SHARES OF   AVERAGE    # SHARES OF   AVERAGE    # SHARES OF   AVERAGE
                                      UNDERLYING    EXERCISE   UNDERLYING    EXERCISE   UNDERLYING    EXERCISE
                                        OPTIONS      PRICES      OPTIONS      PRICES      OPTIONS      PRICES
                                      -----------   --------   -----------   --------   -----------   --------
<S>                                   <C>           <C>        <C>           <C>        <C>           <C>
Outstanding at beginning of the
  year..............................   4,423,595     $31.66     2,603,955     $28.81     1,932,691     $28.53
  Granted...........................     887,600     $52.45     2,429,500     $33.35       709,000     $29.85
  Converted in connection with
     corporate transactions.........          --         NA        37,323     $15.62        40,025     $15.62
  Exercised.........................     821,688     $30.56       620,298     $25.57        38,761     $19.17
  Forfeited.........................      98,400     $43.53        26,885     $28.88        39,000     $29.94
                                       ---------                ---------                ---------
Outstanding at end of year..........   4,391,107     $35.80     4,423,595     $31.66     2,603,955     $28.81
                                       =========                =========                =========
Exercisable at end of year..........   2,003,254     $30.86     1,980,095     $29.63     1,934,950     $28.50
                                       =========                =========                =========
</TABLE>
 
     The fair value of each stock option granted is estimated on the date of
grant using the Black-Scholes option-pricing model with the following
weighted-average assumptions:
 
<TABLE>
<CAPTION>
                        ASSUMPTION:                           1997     1996     1995
                        -----------                           -----    -----    -----
<S>                                                           <C>      <C>      <C>
Expected Term in Years......................................      3        3        3
Expected Volatility.........................................   17.3%    20.3%    16.7%
Expected Dividends..........................................    3.0%     3.0%     3.0%
Risk-Free Interest Rate.....................................    6.3%     5.5%     7.3%
</TABLE>
 
     The Black-Scholes weighted average fair value of options granted during
1997, 1996 and 1995 was as follows:
 
<TABLE>
<CAPTION>
                                                            1997      1996      1995
                                                           ------    ------    ------
<S>                                                        <C>       <C>       <C>
Weighted-average fair value of options granted at a
  discount...............................................  $11.92    $20.51    $13.34
Weighted-average fair value of options granted at
  market.................................................  $ 7.71    $ 5.16    $ 4.86
</TABLE>
 
     Options outstanding as of December 31, 1997 are summarized below:
 
<TABLE>
<CAPTION>
                                           OPTIONS OUTSTANDING                        OPTIONS EXERCISABLE
                            -------------------------------------------------    -----------------------------
                              NUMBER       WEIGHTED AVERAGE       WEIGHTED         NUMBER          WEIGHTED
         RANGE OF           OUTSTANDING       REMAINING           AVERAGE        EXERCISABLE       AVERAGE
     EXERCISE PRICES        AT 12/31/97    CONTRACTUAL LIFE    EXERCISE PRICE    AT 12/31/97    EXERCISE PRICE
     ---------------        -----------    ----------------    --------------    -----------    --------------
<S>                         <C>            <C>                 <C>               <C>            <C>
$15.62 to $22.91               319,620           4.12              $18.58           319,620         $18.58
$25.69 to $38.19             3,057,287            7.5              $32.45         1,614,301         $32.58
$39.56 to $54.19               952,000            9.3              $50.89            59,333         $45.66
$55.78 to $60.34                62,200           9.61              $58.05            10,000         $57.97
                             ---------                                            ---------
$15.62 to $60.34             4,391,107           7.68              $35.80         2,003,254         $30.86
                             =========                                            =========
</TABLE>
 
  Restricted Stock
 
     Under the Company's various stock-based compensation plans, common stock of
the Company may be granted at no cost to certain key officers and employees.
These shares carry voting and dividend rights; however, sale or transfer of the
shares is restricted in accordance with the vesting procedures. These restricted
stock awards will vest if the Company achieves certain performance targets
and/or over a specific period of time. Approximately 96 percent of the awards
outstanding as of December 31, 1997, were performance vested.
                                       59
<PAGE>   64
 
Since the date of inception through December 31, 1997, 2.4 million shares of
restricted stock with a weighted average grant-date fair value of $37.86 had
been issued under the Company's various stock-based compensation plans. The
value of these shares is determined based on the fair market value on the
measurement dates and is charged to compensation expense ratably over the
restriction period based on the number of shares earned over the vesting period.
For 1997, 1996, and 1995, these charges totaled $19 million, $5 million, and $.3
million, respectively. The unamortized balance at December 31, 1997, was $71
million and is recorded as a reduction to stockholder's equity.
 
  Performance Units
 
     Certain employees and officers of the Company are awarded performance units
that are payable in cash or stock at the end of the vesting period. The final
value of the performance units may vary according to the plan under which they
are granted, but is usually based on the Company's stock price at the end of the
vesting period. The value of the performance units is charged ratably to
compensation expense over the vesting period with periodic adjustments to
account for the fluctuation in the market price of the Company's stock. Amounts
charged to compensation expense in 1997, 1996, and 1995 were $4 million, $5
million, and $7 million, respectively.
 
  Pro Forma Net Income and Net Income Per Common Share
 
     Had the compensation expense for the Company's stock-based compensation
plans been determined consistent with SFAS No. 123, the Company's net income and
net income per common share for 1997, 1996, and 1995 would approximate the pro
forma amounts below:
 
<TABLE>
<CAPTION>
                                      DECEMBER 31, 1997         DECEMBER 31, 1996         DECEMBER 31, 1995
                                   -----------------------   -----------------------   -----------------------
                                   AS REPORTED   PRO FORMA   AS REPORTED   PRO FORMA   AS REPORTED   PRO FORMA
                                   -----------   ---------   -----------   ---------   -----------   ---------
<S>                                <C>           <C>         <C>           <C>         <C>           <C>
SFAS No. 123 charge, pretax......     $  --        $  28        $  --        $  15        $  --        $  12
APB No. 25 charge, pretax........     $  24        $  --        $  13        $  --        $  10        $  --
Net income.......................     $ 186        $ 183        $  38        $  36        $  85        $  83
Basic earnings per common
  share..........................     $3.27        $3.21        $1.06        $1.00        $2.47        $2.42
Diluted earnings per common
  share..........................     $3.18        $3.12        $1.04        $0.98        $2.47        $2.42
</TABLE>
 
     The effects of applying SFAS No. 123 in this pro forma disclosure are not
indicative of future amounts. SFAS No. 123 does not apply to awards granted
prior to the 1995 fiscal year.
 
     The maximum number of shares for which stock options or restricted stock
awards may be granted under EPG's current stock-based compensation plans is
approximately 9 million shares of common stock
(which includes grants previously made), to be issued from shares held in EPG's
treasury, or out of authorized but unissued shares of common stock, or partly
out of each, as determined by the Board.
 
9. EMPLOYEE BENEFITS
 
  Pensions
 
     Prior to January 1, 1997, the Company maintained a defined benefit pension
plan covering all employees of the Company, except leased employees. Pension
benefits were based on years of credited service and final 5-year average
compensation, and have maximum limitations as defined in the pension plan.
 
     During 1996, the Company offered early retirement window benefits to
employees with at least five years of service and at least 52 years old on
February 29, 1996. Under the early retirement window, benefits were determined
by adding three years to age and, if otherwise eligible for early retirement,
adding three years to credited service. Approximately 400 employees accepted the
offer and retired during 1996. The Company further reduced its workforce by
approximately 500 employees through an involuntary reduction-in-force. During
the first quarter of 1996, the Company recognized a $21 million charge to
pension expense for the early retirement window and workforce reductions.
 
                                       60
<PAGE>   65
 
     Effective January 1, 1997, the plan was amended to provide benefits
determined by a cash balance formula. Participants were credited with an initial
cash balance equivalent to accrued benefits on December 31, 1996. Participant
accounts are credited with a percentage of pay based on age and service, and
interest based on prevailing market yields on certain U.S. treasury obligations.
Participants receive the greater of cash balance benefits or prior plan benefits
accrued through December 31, 2001. EPTPC, Cornerstone and EPEM employees
commenced participation on January 1, 1997, with no account balance for prior
service.
 
     During 1997, the Company offered special termination benefits to EPTPC
employees who were at least 55 years old on December 31, 1996 and who were
vested in the Tenneco Energy Pension Plan. The 220 employees accepting this
offer received an enhanced cash balance equivalent to and in lieu of severance
benefits provided pursuant to the merger agreement. The cost associated with
their special termination benefits was accrued at December 31, 1996 as part of
the liabilities assumed in the Merger. In 1997, the Company funded $11 million
for these special termination benefits.
 
     The following table sets forth the components of net periodic pension cost
for the three years ended December 31:
 
<TABLE>
<CAPTION>
                                                              1997    1996    1995
                                                              ----    ----    ----
                                                                 (IN MILLIONS)
<S>                                                           <C>     <C>     <C>
Service cost -- benefits earned during the period...........  $ 12    $  7    $  9
Interest cost on projected benefit obligation...............    38      41      41
Actual return on plan assets................................   (79)    (65)    (86)
Net amortization and deferral...............................    35      26      49
Curtailment and special termination benefits expense........    --      21      --
                                                              ----    ----    ----
Net periodic pension cost...................................  $  6    $ 30    $ 13
                                                              ====    ====    ====
</TABLE>
 
     The following table sets forth the qualified pension plan's funded status
and amounts recognized in the Company's Consolidated Balance Sheets at December
31:
 
<TABLE>
<CAPTION>
                                                              1997     1996
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Actuarial present value of benefit obligations
  Vested benefits...........................................  $513     $483
  Nonvested benefits........................................     1        1
                                                              ----     ----
Accumulated benefit obligation..............................   514      484
Additional amounts related to projected salary increases....    20       21
                                                              ----     ----
Projected benefit obligation for service rendered to date...   534      505
Plan assets at fair value, primarily listed stocks and
  government securities.....................................   547      498
                                                              ----     ----
Projected benefit obligation in excess of (less than) plan
  assets....................................................  $(13)    $  7
                                                              ====     ====
Unrecognized net (gain) loss................................  $ (4)    $  4
Unrecognized net transition obligation......................     8       10
Unrecognized prior service cost.............................   (38)     (40)
Recognized pension liability................................    21       33
                                                              ----     ----
Projected benefit obligation in excess of (less than) plan
  assets....................................................  $(13)    $  7
                                                              ====     ====
</TABLE>
 
     The accumulated vested benefit obligation is the actuarial present value of
the vested benefits to which the employee is currently entitled, but it is based
on the employee's expected date of termination.
 
                                       61
<PAGE>   66
 
     The following table reflects the actuarial assumptions used in the
valuation of the projected benefit obligation at December 31:
 
<TABLE>
<CAPTION>
                                                              1997     1996
                                                              -----    -----
<S>                                                           <C>      <C>
Weighted average discount rate..............................  7.00%    7.75%
Rate of increase in future compensation levels..............  4.50%    5.00%
Weighted average expected long-term rate of return on plan
  assets....................................................  9.25%    9.25%
</TABLE>
 
  Retirement Savings Plan
 
     The Company maintains a defined contribution plan covering all employees of
the Company. During 1995 and the first six months of 1996, the Company made
matching contributions equal to a participant's basic contributions of up to 6
percent where the participant had fewer than 10 years of employment with the
Company, or up to 8 percent where the participant had 10 or more years of
employment with the Company. In February 1996, the Company changed its matching
contribution to 75 percent of a participant's basic contributions of up to 6
percent, with the matching contribution being made in Company stock. Amounts
expensed under the plan were approximately $9 million, $4 million and $8 million
for the years ended December 31, 1997, 1996, and 1995, respectively.
 
  Postretirement Benefits, Other than Pensions
 
     The Financial Accounting Standards Board issued SFAS No. 106, Employers'
Accounting for Post Retirement Benefits Other Than Pensions, which requires
companies to account for OPEB (principally retiree medical costs) on an accrual
basis versus the pay-as-you-go basis. The Company adopted SFAS No. 106 effective
January 1, 1993, and elected 20-year amortization of the transition obligation.
 
     EPG provides a non-contributory defined benefit postretirement medical plan
that covers employees who retired on or before March 1, 1986, and limited
postretirement life insurance for employees who retire after January 1, 1985. As
such, EPG's obligation to accrue for OPEB is primarily limited to the fixed
population of retirees who retired on or before March 1, 1986. The medical plan
is pre-funded to the extent employer contributions are recoverable through
rates.
 
     EPG began recovering through its rates the OPEB costs included in the
January 1993 rate case settlement agreement. To the extent actual OPEB costs
differ from the amounts funded, a regulatory asset or liability is recorded.
 
     As a result of the Merger, TGP assumed responsibility for certain benefits
for former employees of Old Tenneco and the postretirement health care plans for
employees of TGP were significantly changed. TGP will be responsible for
benefits for both TGP former employees and former employees of operations
previously disposed of by Old Tenneco. TGP employees who retired before July 1,
1997 received the same benefits as former employees. While TGP employees who
retire on or after July 1, 1997 will continue to receive $10,000 of
postretirement life insurance, they will not receive any employer subsidized
postretirement health care benefits. All of these benefits may be subject to
deductibles, co-payment provisions and other limitations. The Company has
reserved the right to change these benefits.
 
     The majority of TGP's postretirement benefit plans are not funded. In June
1994, two trusts were established to fund postretirement benefits for certain
plan participants of TGP. The contributions are collected from customers in
FERC-approved rates.
 
                                       62
<PAGE>   67
 
     The following table reflects the components of net periodic postretirement
benefit cost for the three years ended December 31:
 
<TABLE>
<CAPTION>
                                                              1997   1996   1995
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Interest cost on accumulated postretirement benefit
  obligation................................................  $31    $ 6    $ 7
Actual (return) loss on plan assets.........................   (7)    (4)    (5)
Net amortization and deferral...............................    8      9     10
                                                              ---    ---    ---
Net periodic postretirement benefit cost....................  $32    $11    $12
                                                              ===    ===    ===
</TABLE>
 
     The following table sets forth the funded status of the Company's
postretirement plans and amounts recognized in the Company's Consolidated
Balance Sheets at December 31:
 
<TABLE>
<CAPTION>
                                                              1997     1996
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Accumulated postretirement benefit obligation...............  $417     $426
Plan assets at fair value, primarily U.S. stocks and U.S.
  bonds.....................................................    55       41
                                                              ----     ----
Accumulated postretirement benefit obligation in excess of
  plan assets...............................................  $362     $385
                                                              ====     ====
Unrecognized net gain.......................................  $(26)    $(40)
Unrecognized transition obligation..........................    70       79
Accrued postretirement benefit cost.........................   318      346
                                                              ----     ----
Accumulated postretirement benefit obligation in excess of
  plan assets...............................................  $362     $385
                                                              ====     ====
</TABLE>
 
     As of December 31, 1997 and 1996, the current portion of the postretirement
benefits was $77 million and $76 million, respectively. The accrued
postretirement benefit cost for 1997 has been recorded based upon certain
actuarial estimates as described below. Those estimates are subject to revision
in future periods given new facts or circumstances.
 
     Actuarial estimates for the Company's plans assumed a weighted average
annual rate of increase in the per capita costs of covered health care benefits
of 5.5 percent for 1998, gradually decreasing to 5.1 percent by the year 2003.
Increasing the assumed health care cost trend rates by one percentage point in
each year would increase the accumulated postretirement benefit obligation at
December 31, 1997, by approximately $9 million and increase the interest cost
component of net periodic postretirement benefit cost for 1997 by approximately
$0.6 million. A discount rate of 7.00 percent and 7.75 percent was used to
determine the accumulated postretirement benefit obligation at December 31,
1997, and 1996, respectively. The weighted average expected long-term rate of
return for 1997 was approximately 8.5 percent.
 
10. EMPLOYEE SEPARATION AND ASSET IMPAIRMENT CHARGE
 
     During the first quarter of 1996, the Company adopted a program to reduce
operating costs through work force reductions and improved work processes and
adopted SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of. As a result of the workforce reduction
program and the adoption of SFAS No. 121, the Company recorded a special charge
of $99 million ($47 million for employee separation costs and $52 million for
asset impairments) in the first quarter of 1996.
 
     The employee separation charge included approximately $26 million for
expected severance-related costs and $21 million for pension costs related to
special termination benefits and work force reductions. The special charge for
pension-related costs will have no cash impact outside of the normal funding of
the Company's pension plan.
 
     In accordance with SFAS No. 121, the Company determined the fair value of
certain assets based on discounted future cash flows. The resultant non-cash
charge for asset impairments included approximately $44 million for the
impairment of certain natural gas gathering, processing, and production
facilities and $8 million for the write-off of a regulatory asset established
upon the adoption of SFAS No. 112, Employers'
 
                                       63
<PAGE>   68
 
Accounting for Postemployment Benefits, but not recoverable through the
Company's rate settlement filed with FERC in March 1996.
 
11. PREFERRED STOCK OF SUBSIDIARY
 
     In November 1996, EPTPC issued in a public offering 6 million shares of
8 1/4% cumulative preferred stock with a par value of $50 per share for $296
million (net of issuance costs). The preferred stock is redeemable, at the
option of EPTPC, after December 31, 2001, at a redemption price equal to $50 per
share, plus dividends accrued and unpaid up to the date of redemption.
 
     During 1997 and 1996, dividends of approximately $25 million and $3
million, respectively, were paid on the cumulative preferred stock, of which for
1996 approximately $2 million is reflected as minority interest on the income
statement for the 20 days EPTPC is included in the 1996 consolidated results of
operations.
 
12. SEGMENT INFORMATION
 
     To the extent practicable, the following information for 1996 and 1995 has
been reclassified to conform to the current business segment presentation.
 
<TABLE>
<CAPTION>
       FOR YEARS ENDED         NATURAL GAS    FIELD &    CORPORATE
         DECEMBER 31           TRANSMISSION   MERCHANT    & OTHER    ELIMINATIONS   CONSOLIDATED
       ---------------         ------------   --------   ---------   ------------   ------------
                                                         (IN MILLIONS)
<S>                            <C>            <C>        <C>         <C>            <C>
Operating Revenues
  1997.......................     $1,319       $4,342     $   19        $  (42)        $5,638
  1996.......................        558        2,461          1            (8)         3,012
  1995.......................        540          492          8            (2)         1,038
Operating Income (Loss)
  1997.......................        560           34        (73)           --            521
  1996.......................        223           57       (110)           --            170
  1995.......................        203            1          8            --            212
Depreciation, Depletion and
  Amortization
  1997.......................        193           37          6            --            236
  1996.......................         70           30          1            --            101
  1995.......................         53           19         --            --             72
Identifiable Assets
  1997.......................      7,018        1,727        757            --          9,502
  1996.......................      6,139        1,276      1,297            --          8,712
  1995.......................      1,867          556        138           (26)         2,535
Capital Expenditures
  1997.......................        195           70         28            --            293
  1996.......................         55           64         --            --            119
  1995.......................         92           74         --            --            166
</TABLE>
 
     Operating revenues by segment include both sales to unaffiliated customers
and intersegment sales (which are accounted for principally at market prices and
eliminated in consolidation).
 
13. INVENTORIES
 
     Inventories consisted of the following at December 31:
 
<TABLE>
<CAPTION>
                                                              1997     1996
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Materials and supplies......................................   $42      $51
Gas in storage..............................................    26       36
                                                               ---      ---
          Total.............................................   $68      $87
                                                               ===      ===
</TABLE>
 
                                       64
<PAGE>   69
 
14. PROPERTY, PLANT, AND EQUIPMENT
 
     Property, plant, and equipment consisted of the following at December 31:
 
<TABLE>
<CAPTION>
                                                               1997      1996
                                                              ------    ------
                                                               (IN MILLIONS)
<S>                                                           <C>       <C>
Property, plant, and equipment, at cost.....................  $6,004    $5,474
Less accumulated depreciation and depletion.................   1,395     1,207
                                                              ------    ------
                                                               4,609     4,267
Additional acquisition cost assigned to utility plant, net
  of accumulated amortization...............................   2,507     1,671
                                                              ------    ------
          Total property, plant, and equipment, net.........  $7,116    $5,938
                                                              ======    ======
</TABLE>
 
15. EARNINGS PER SHARE
 
     In March 1997, the Financial Accounting Standards Board issued SFAS No.
128, Earnings Per Share, which establishes new guidelines for calculating
earnings per share. The pronouncement is effective for reporting periods ending
after December 15, 1997. SFAS No. 128 requires companies to present both a basic
and diluted earnings per share amount on the face of the statement of income and
to restate prior period earnings per share amounts to comply with this standard.
Basic and diluted earnings per share amounts calculated in accordance with SFAS
No. 128 are presented below for the years ended December 31, 1997, 1996, and
1995.
 
<TABLE>
<CAPTION>
                                                    1997              1996              1995
                                               ---------------   ---------------   ---------------
                                               BASIC   DILUTED   BASIC   DILUTED   BASIC   DILUTED
                                               -----   -------   -----   -------   -----   -------
<S>                                            <C>     <C>       <C>     <C>       <C>     <C>
(In millions, except per common share
  amounts)
Net income...................................  $ 186   $  186    $  38   $   38    $  85   $   85
                                               =====   ======    =====   ======    =====   ======
Average common shares outstanding............   57.0     57.0     36.1     36.1     34.4     34.4
Effect of dilutive securities
          Restricted stock...................     --       .7       --       .5       --       --
          Stock options......................     --      1.0       --       --       --       --
                                               -----   ------    -----   ------    -----   ------
Adjusted average common shares outstanding...   57.0     58.7     36.1     36.6     34.4     34.4
                                               =====   ======    =====   ======    =====   ======
Earnings per common share....................  $3.27   $ 3.18    $1.06   $ 1.04    $2.47   $ 2.47
                                               =====   ======    =====   ======    =====   ======
</TABLE>
 
16. NATURE OF OPERATIONS AND SIGNIFICANT CUSTOMERS
 
     The Company is principally engaged in the transportation, gathering and
processing, and marketing of natural gas. For the year ended December 31, 1997,
the Company's operating revenues were predominately derived from the marketing
and transportation of natural gas and other commodities.
 
     The Company had gross revenues equal to, or in excess of, 10 percent of
consolidated operating revenues from the following customers for the years ended
December 31:
 
<TABLE>
<CAPTION>
                                                            1997      1996      1995
                                                            ----      ----      ----
                                                                 (IN MILLIONS)
<S>                                                         <C>       <C>       <C>
Southern California Gas Company...........................    --(a)     --(a)   $176
Pacific Gas & Electric Company............................    --(a)     --(a)    128
</TABLE>
 
---------------
 
(a) Less than 10 percent of consolidated operating revenues.
 
                                       65
<PAGE>   70
 
17. SUPPLEMENTAL CASH FLOW INFORMATION
 
     The following table contains supplemental cash flow information for the
years ended December 31:
 
<TABLE>
<CAPTION>
                                                             1997      1996      1995
                                                             ----      ----      ----
                                                                  (IN MILLIONS)
<S>                                                          <C>       <C>       <C>
Interest...................................................  $249      $85       $77
Income tax payments (refunds)..............................   (34)      49        10
</TABLE>
 
     See Note 2, Acquisitions, for a discussion of the non-cash investing
transaction related to certain acquisitions.
 
18. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
 
     Financial information by quarter is summarized below. In the opinion of
management, all adjustments necessary for a fair presentation have been made.
 
<TABLE>
<CAPTION>
                                                                     QUARTERS ENDED
                                                     -----------------------------------------------
                                                     DECEMBER 31   SEPTEMBER 30   JUNE 30   MARCH 31
                                                     -----------   ------------   -------   --------
                                                     (IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<S>                                                  <C>           <C>            <C>       <C>
1997
  Operating revenues...............................    $1,577         $1,251       $ 979     $1,831
  Operating income.................................       137            120         125        139
  Net income.......................................        52             44          43         47
  Basic earnings per common share..................      0.90           0.77        0.75       0.85
  Diluted earnings per share.......................      0.87           0.75        0.74       0.84
1996
  Operating revenues...............................    $1,074         $  745       $ 587     $  606
  Operating income (loss)..........................        75             66          62        (33)
  Net income (loss)................................        24             25          24        (35)
  Basic earnings (loss) per common share...........      0.61           0.70        0.69      (1.01)
  Diluted earnings per share.......................      0.60           0.68        0.69      (1.01)
</TABLE>
 
                                       66
<PAGE>   71
 
                       REPORT OF INDEPENDENT ACCOUNTANTS
 
To the Board of Directors and Stockholders
El Paso Natural Gas Company:
 
     We have audited the consolidated financial statements and the financial
statement schedule of El Paso Natural Gas Company listed in Item 14(a) of this
Form 10-K. 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 in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
 
     In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of El Paso Natural
Gas Company as of December 31, 1997 and 1996, and the consolidated results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1997, in conformity with generally accepted accounting
principles. In addition, in our opinion, the financial statement schedule
referred to above, when considered in relation to the basic financial statements
taken as a whole, presents fairly, in all material respects, the information
required to be included therein.
 
COOPERS & LYBRAND L.L.P.
 
Houston, Texas
March 12, 1998
 
                                       67
<PAGE>   72
 
                                  SCHEDULE II
 
                          EL PASO NATURAL GAS COMPANY
                       VALUATION AND QUALIFYING ACCOUNTS
 
                 YEARS ENDED DECEMBER 31, 1997, 1996, AND 1995
                                 (IN MILLIONS)
 
<TABLE>
<CAPTION>
                 COLUMN A                     COLUMN B         COLUMN C          COLUMN D    COLUMN E
                 --------                    ----------   -------------------   ----------   ---------
                                                          CHARGED
                                             BALANCE AT   TO COSTS   CHARGED                  BALANCE
                                             BEGINNING      AND      TO OTHER                 AT END
                DESCRIPTION                  OF PERIOD    EXPENSES   ACCOUNTS   DEDUCTIONS   OF PERIOD
                -----------                  ----------   --------   --------   ----------   ---------
<S>                                          <C>          <C>        <C>        <C>          <C>
1997
  Allowance for doubtful accounts..........     $ 64        $ 21       $ --        $ 61(b)     $ 24
  Valuation allowance on deferred tax
     assets................................       --          --          8(c)       --           8
1996
  Allowance for doubtful accounts..........     $ 11        $  6       $ 51(a)     $  4        $ 64
1995
  Allowance for doubtful accounts..........     $ 24        $  2       $  2        $ 17(b)     $ 11
</TABLE>
 
---------------
 
(a) Primarily due to acquisition of EPTPC.
 
(b) Primarily accounts written off.
 
(c) Due to acquisition of Gulf States Gas Pipeline Company.
 
                                       68
<PAGE>   73
 
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 captions "Proposal No. 1 -- Election of
Directors" and "Section 16(a) Beneficial Ownership Reporting Compliance" in
EPG's proxy statement for the 1998 Annual Meeting of Stockholders is
incorporated herein by reference. Information regarding executive officers of
the Company is presented in Item 1 of this Form 10-K under the caption
"Executive Officers of the Registrant."
 
ITEM 11. EXECUTIVE COMPENSATION
 
     Information appearing under the caption "Executive Compensation" in EPG's
proxy statement for the 1998 Annual Meeting of Stockholders is incorporated
herein by reference.
 
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
 
     Information appearing under the caption "Security Ownership of Beneficial
Owner and Management" in EPG's proxy statement for the 1998 Annual Meeting of
Stockholders is incorporated herein by reference.
 
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
 
     None.
 
                                    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 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
     Consolidated Statements of Stockholders' Equity........   37
     Notes to Consolidated Financial Statements.............   38
     Report of independent accountants......................   67
 
2. Financial statement schedules and supplementary information
  required to be submitted.
 
     Schedule II -- Valuation and qualifying accounts.......   68
     Schedules other than that listed above are omitted
      because they are not applicable
 
3. Exhibit list.............................................   70
</TABLE>
 
     (B) REPORTS ON FORM 8-K:
 
     On November 3, 1997, EPG filed a report under Item 5 and Item 7 on Form
8-K, dated November 3, 1997, with respect to the purchase of PacifiCorp's
offshore gathering and processing subsidiaries.
 
                                       69
<PAGE>   74
 
                          EL PASO NATURAL GAS COMPANY
 
                                  EXHIBIT LIST
                               DECEMBER 31, 1997
 
     Each exhibit identified below is filed as a part of this report. Exhibits
not incorporated by reference to a prior filing are designated by an asterisk;
all exhibits not so designated are incorporated herein by reference to a prior
filing as indicated. Exhibits designated with a "+" constitute a management
contract or compensatory plan or arrangement required to be filed as an exhibit
to this report pursuant to Item 14(c) of Form 10-K.
 
<TABLE>
<CAPTION>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
          2              -- Amended and Restated Merger Agreement dated as of June
                            19, 1996 among El Paso Natural Gas Company, El Paso
                            Merger Company and Tenneco Inc. (Exhibit 2.A to EPG's
                            Registration Statement on Form S-4, No. 333-10911, filed
                            October 21, 1996).
          3.A            -- Restated Certificate of Incorporation of EPG dated
                            January 22, 1992 (Exhibit 3.A to EPG's Form 10-K filed
                            January 29, 1992); Certificate of Designation,
                            Preferences and Rights of Series A Junior Participating
                            Preferred Stock of EPG, dated July 7, 1992, (Exhibit
                            3.A.1 to EPG's Form 10-K filed February 3, 1993).
         *3.A.1          -- Certificate of Amendment to Restated Certificate of
                            Incorporation of EPG, dated March 2, 1998.
          3.B            -- By-laws of EPG, as amended October 22, 1997. (Exhibit 3.B
                            to EPG's Form 10-Q filed November 13, 1997.)
          4              -- Amended and Restated Shareholder Rights Agreement dated
                            as of July 23, 1997 (Exhibit 1 to Form 8-A/A, filed
                            August 13, 1997).
         10.A            -- $750 million 364-Day Revolving Credit and Competitive
                            Advance Facility Agreement dated as of October 29, 1997
                            between EPG, The Chase Manhattan Bank, Citibank, N.A.,
                            Morgan Guaranty Trust Company of New York, and certain
                            other banks (Exhibit 10.E to EPG's Form 10-Q filed
                            November 13, 1997).
         10.B            -- $750 million 5-Year Revolving Credit and Competitive
                            Advance Facility Agreement dated as of October 29, 1997
                            between EPG, The Chase Manhattan Bank, Citibank, N.A.,
                            Morgan Guaranty Trust Company of New York, and certain
                            other banks (Exhibit 10-F to EPG's Form 10-Q filed
                            November 13, 1997).
        +10.C            -- Omnibus Compensation Plan, dated as of January 1, 1992,
                            (Exhibit 10.1 to EPG's Registration Statement on Form
                            S-2, No. 33-45369, filed February 27, 1992).
        +10.D            -- 1995 Incentive Compensation Plan, effective as of January
                            13, 1995 (Form S-8, No. 33-57553, filed February 2,
                            1995); Amendment No. 1 to EPG's 1995 Incentive
                            Compensation Plan, effective as of July 1, 1995 (Exhibit
                            10.J.1 to EPG's Form 10-Q filed July 21, 1995); Amendment
                            No. 2 to the 1995 Incentive Compensation Plan effective
                            January 1, 1996 (Exhibit 10.J.1 to EPG's Form 10-K filed
                            March 15, 1996).
       *+10.E            -- 1995 Compensation Plan for Non-Employee Directors,
                            Amended and Restated effective as of January 1, 1998.
       *+10.F            -- Stock Option Plan for Non-Employee Directors, Amended and
                            Restated effective as of January 1, 1998.
        +10.G            -- 1995 Omnibus Compensation Plan effective as of January
                            13, 1995 (Exhibit 4.2 to EPG's Registration Statement on
                            Form S-8, No. 33-57553, filed February 2, 1995);
                            Amendment No. 1 to EPG's 1995 Omnibus Compensation Plan,
                            effective as of July 21, 1995 (Exhibit 10.2.1 to EPG's
                            Form 10-Q filed July 21, 1995).
        +10.H            -- Supplemental Benefits Plan, Amended and Restated
                            effective as of January 13, 1995 (Exhibit 10.N to EPG's
                            Form 10-K filed January 26, 1995).
</TABLE>
 
                                       70
<PAGE>   75
 
<TABLE>
<CAPTION>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
        +10.I            -- Senior Executive Survivor Benefit Plan, effective January
                            1, 1992 (Exhibit 10.7 to EPG's Registration Statement on
                            Form S-2, No. 33-45369, filed February 27, 1992).
        +10.J            -- Deferred Compensation Plan, Amended and Restated
                            effective as of January 13, 1995 (Exhibit 10.P to EPG's
                            Form 10-K filed January 26, 1995).
        +10.K            -- Retirement Income Plan for Non-Employee Directors,
                            Amended and Restated effective as of January 13, 1995
                            (Exhibit 10.Q to EPG's Form 10-K filed January 26, 1995).
        +10.L            -- Key Executive Severance Protection Plan, Amended and
                            Restated effective as of January 13, 1995 (Exhibit 10.R
                            to EPG's Form 10-K filed January 26, 1995).
        +10.M            -- Director Charitable Award Plan, Amended and Restated
                            effective as of January 13, 1995 (Exhibit 10.S to EPG's
                            Form 10-K filed January 26, 1995); Amendment No. 1 to the
                            Director Charitable Award Plan, effective as of January
                            22, 1996 (Exhibit 10.S.1 to EPG's Form 10-K filed March
                            15, 1996).
        +10.N            -- Employment Agreement dated July 31, 1992, between EPG and
                            William A. Wise (Exhibit 10.U to EPG's Form 10-K filed
                            February 3, 1993); Amendment to Employment Agreement
                            dated January 29, 1996, between EPG and William A. Wise
                            (Exhibit 10.U.1 to EPG's Form 10-K filed March 15, 1996).
        +10.O            -- Letter Agreement dated February 22, 1991, between EPG and
                            Britton White, Jr. (Exhibit 10.W to EPG's Form 10-K filed
                            February 3, 1993).
        +10.P            -- Letter Agreement dated January 13, 1995, between EPG and
                            William A. Wise (Exhibit 10.X to EPG's Form 10-K filed
                            January 26, 1995).
       *+10.Q            -- Domestic Relocation Policy, effective as of November 1,
                            1996.
        *12              -- Computation of Ratio of Earnings to Fixed Charges.
        *21              -- Subsidiaries of the Registrant.
        *23              -- Consent of Independent Accountants.
        *27              -- Financial Data Schedule.
</TABLE>
 
UNDERTAKING.
 
     The undersigned, El Paso Natural Gas Company, 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 El Paso Natural Gas Company 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 El Paso Natural Gas Company and its
consolidated subsidiaries.
 
                                       71
<PAGE>   76
 
                                   SIGNATURES
 
     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, El Paso Natural Gas Company has duly caused this report to
be signed on its behalf by the undersigned, thereunto duly authorized on the
20th day of March 1998.
 
                                           EL PASO NATURAL GAS COMPANY
                                                     Registrant
 
                                            By     /s/ WILLIAM A. WISE
                                            ------------------------------------
                                                      William A. Wise
                                              Chairman of the Board and Chief
                                                     Executive Officer
 
     Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of El Paso
Natural Gas Company and in the capacities and on the dates indicated:
 
<TABLE>
<CAPTION>
                      SIGNATURE                                    TITLE                    DATE
                      ---------                                    -----                    ----
<S>                                                    <C>                             <C>
 
                 /s/ WILLIAM A. WISE                   Chairman of the Board, Chief    March 20, 1998
-----------------------------------------------------    Executive Officer and
                  (William A. Wise)                      Director
 
               /s/ RICHARD OWEN BAISH                  President                       March 20, 1998
-----------------------------------------------------
                (Richard Owen Baish)
 
                 /s/ H. BRENT AUSTIN                   Executive Vice President and    March 20, 1998
-----------------------------------------------------    Chief Financial Officer
                  (H. Brent Austin)
 
                /s/ JEFFREY I. BEASON                  Vice President and Controller   March 20, 1998
-----------------------------------------------------    (Chief Accounting Officer)
                 (Jeffrey I. Beason)
 
                /s/ BYRON ALLUMBAUGH                   Director                        March 20, 1998
-----------------------------------------------------
                 (Byron Allumbaugh)
 
               /s/ JUAN CARLOS BRANIFF                 Director                        March 20, 1998
-----------------------------------------------------
                (Juan Carlos Braniff)
 
                 /s/ PETER T. FLAWN                    Director                        March 20, 1998
-----------------------------------------------------
                  (Peter T. Flawn)
 
                /s/ JAMES F. GIBBONS                   Director                        March 20, 1998
-----------------------------------------------------
                 (James F. Gibbons)
 
                   /s/ BEN F. LOVE                     Director                        March 20, 1998
-----------------------------------------------------
                    (Ben F. Love)
 
               /s/ KENNETH L. SMALLEY                  Director                        March 20, 1998
-----------------------------------------------------
                (Kenneth L. Smalley)
 
                 /s/ MALCOLM WALLOP                    Director                        March 20, 1998
-----------------------------------------------------
                  (Malcolm Wallop)
</TABLE>
 
                                       72
<PAGE>   77
 
                                 EXHIBIT INDEX
 
<TABLE>
<CAPTION>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
          2              -- Amended and Restated Merger Agreement dated as of June
                            19, 1996 among El Paso Natural Gas Company, El Paso
                            Merger Company and Tenneco Inc. (Exhibit 2.A to EPG's
                            Registration Statement on Form S-4, No. 333-10911, filed
                            October 21, 1996).
          3.A            -- Restated Certificate of Incorporation of EPG dated
                            January 22, 1992 (Exhibit 3.A to EPG's Form 10-K filed
                            January 29, 1992); Certificate of Designation,
                            Preferences and Rights of Series A Junior Participating
                            Preferred Stock of EPG, dated July 7, 1992, (Exhibit
                            3.A.1 to EPG's Form 10-K filed February 3, 1993).
         *3.A.1          -- Certificate of Amendment to Restated Certificate of
                            Incorporation of EPG, dated March 2, 1998.
          3.B            -- By-laws of EPG, as amended October 22, 1997. (Exhibit 3.B
                            to EPG's Form 10-Q filed November 13, 1997.)
          4              -- Amended and Restated Shareholder Rights Agreement dated
                            as of July 23, 1997 (Exhibit 1 to Form 8-A/A, filed
                            August 13, 1997).
         10.A            -- $750 million 364-Day Revolving Credit and Competitive
                            Advance Facility Agreement dated as of October 29, 1997
                            between EPG, The Chase Manhattan Bank, Citibank, N.A.,
                            Morgan Guaranty Trust Company of New York, and certain
                            other banks (Exhibit 10.E to EPG's Form 10-Q filed
                            November 13, 1997).
         10.B            -- $750 million 5-Year Revolving Credit and Competitive
                            Advance Facility Agreement dated as of October 29, 1997
                            between EPG, The Chase Manhattan Bank, Citibank, N.A.,
                            Morgan Guaranty Trust Company of New York, and certain
                            other banks (Exhibit 10-F to EPG's Form 10-Q filed
                            November 13, 1997).
        +10.C            -- Omnibus Compensation Plan, dated as of January 1, 1992,
                            (Exhibit 10.1 to EPG's Registration Statement on Form
                            S-2, No. 33-45369, filed February 27, 1992).
        +10.D            -- 1995 Incentive Compensation Plan, effective as of January
                            13, 1995 (Form S-8, No. 33-57553, filed February 2,
                            1995); Amendment No. 1 to EPG's 1995 Incentive
                            Compensation Plan, effective as of July 1, 1995 (Exhibit
                            10.J.1 to EPG's Form 10-Q filed July 21, 1995); Amendment
                            No. 2 to the 1995 Incentive Compensation Plan effective
                            January 1, 1996 (Exhibit 10.J.1 to EPG's Form 10-K filed
                            March 15, 1996).
       *+10.E            -- 1995 Compensation Plan for Non-Employee Directors,
                            Amended and Restated effective as of January 1, 1998.
       *+10.F            -- Stock Option Plan for Non-Employee Directors, Amended and
                            Restated effective as of January 1, 1998.
        +10.G            -- 1995 Omnibus Compensation Plan effective as of January
                            13, 1995 (Exhibit 4.2 to EPG's Registration Statement on
                            Form S-8, No. 33-57553, filed February 2, 1995);
                            Amendment No. 1 to EPG's 1995 Omnibus Compensation Plan,
                            effective as of July 21, 1995 (Exhibit 10.2.1 to EPG's
                            Form 10-Q filed July 21, 1995).
        +10.H            -- Supplemental Benefits Plan, Amended and Restated
                            effective as of January 13, 1995 (Exhibit 10.N to EPG's
                            Form 10-K filed January 26, 1995).
        +10.I            -- Senior Executive Survivor Benefit Plan, effective January
                            1, 1992 (Exhibit 10.7 to EPG's Registration Statement on
                            Form S-2, No. 33-45369, filed February 27, 1992).
        +10.J            -- Deferred Compensation Plan, Amended and Restated
                            effective as of January 13, 1995 (Exhibit 10.P to EPG's
                            Form 10-K filed January 26, 1995).
        +10.K            -- Retirement Income Plan for Non-Employee Directors,
                            Amended and Restated effective as of January 13, 1995
                            (Exhibit 10.Q to EPG's Form 10-K filed January 26, 1995).
</TABLE>
<PAGE>   78
 
<TABLE>
<CAPTION>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
        +10.L            -- Key Executive Severance Protection Plan, Amended and
                            Restated effective as of January 13, 1995 (Exhibit 10.R
                            to EPG's Form 10-K filed January 26, 1995).
        +10.M            -- Director Charitable Award Plan, Amended and Restated
                            effective as of January 13, 1995 (Exhibit 10.S to EPG's
                            Form 10-K filed January 26, 1995); Amendment No. 1 to the
                            Director Charitable Award Plan, effective as of January
                            22, 1996 (Exhibit 10.S.1 to EPG's Form 10-K filed March
                            15, 1996).
        +10.N            -- Employment Agreement dated July 31, 1992, between EPG and
                            William A. Wise (Exhibit 10.U to EPG's Form 10-K filed
                            February 3, 1993); Amendment to Employment Agreement
                            dated January 29, 1996, between EPG and William A. Wise
                            (Exhibit 10.U.1 to EPG's Form 10-K filed March 15, 1996).
        +10.O            -- Letter Agreement dated February 22, 1991, between EPG and
                            Britton White, Jr. (Exhibit 10.W to EPG's Form 10-K filed
                            February 3, 1993).
        +10.P            -- Letter Agreement dated January 13, 1995, between EPG and
                            William A. Wise (Exhibit 10.X to EPG's Form 10-K filed
                            January 26, 1995).
       *+10.Q            -- Domestic Relocation Policy, effective as of November 1,
                            1996.
        *12              -- Computation of Ratio of Earnings to Fixed Charges.
        *21              -- Subsidiaries of the Registrant.
        *23              -- Consent of Independent Accountants.
        *27              -- Financial Data Schedule.
</TABLE>
 
     Each exhibit identified on this Exhibit List is filed as a part of this
report. Exhibits not incorporated by reference to a prior filing are designated
by an asterisk; all exhibits not so designated are incorporated herein by
reference to a prior filing as indicated. Exhibits designated with a "+"
constitute a management contract or compensatory plan or arrangement required to
be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.