<PAGE>   1
 
                                 UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
 
                             WASHINGTON, D.C. 20549
                             ---------------------
 
                                   FORM 10-K
 
 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
                                      1934
 
                      FOR THE YEAR ENDED DECEMBER 31, 1995
 
                         COMMISSION FILE NUMBER 1-3196
                             ---------------------
 
                        CONSOLIDATED NATURAL GAS COMPANY
 
                             A DELAWARE CORPORATION
            CNG TOWER, 625 LIBERTY AVENUE, PITTSBURGH, PA 15222-3199
                            TELEPHONE (412) 227-1000
                 IRS EMPLOYER IDENTIFICATION NUMBER 13-0596475
                             ---------------------
          SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
 
<TABLE>
    <S>                                                 <C>
    Common Stock:                                       Registered:
      $2.75 Par Value                                             New York Stock Exchange

    Common Stock Purchase Rights                                  New York Stock Exchange

    Debentures:
      7 3/8 % Debentures Due April 1, 2005                        New York Stock Exchange
      6 5/8 % Debentures Due December 1, 2013                     New York Stock Exchange
      5 3/4 % Debentures Due August 1, 2003                       New York Stock Exchange
      5 7/8 % Debentures Due October 1, 1998                      New York Stock Exchange
      8 3/4 % Debentures Due October 1, 2019                      New York Stock Exchange
      8 3/4 % Debentures Due June 1, 1999                         New York Stock Exchange
      9 3/8 % Debentures Due February 1, 1997                     New York Stock Exchange
      8 5/8 % Debentures Due December 1, 2011                     New York Stock Exchange

    Convertible Subordinated Debentures:
      7 1/4 % Convertible Subordinated Debentures
       Due December 15, 2015                                      New York Stock Exchange
</TABLE>
 
        SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE
                             ---------------------
 
     Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.  /X/
 
     Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months and (2) has been subject to such filing
requirements for the past 90 days.     Yes  X        No
                                           ---          --- 

     The aggregate market value of the voting stock held by non-affiliates of
the registrant amounted to $4,217,017,725 as of January 31, 1996. It was assumed
in this calculation that the registrant's affiliates are all of its directors
and/or officers, and they beneficially owned 298,744 shares of voting stock at
that date.
 
     Number of shares of Common Stock, $2.75 Par Value, outstanding at January
31, 1996: 94,010,249.
 
     The registrant's "Notice of Annual Meeting and Proxy Statement, 1996" is
hereby incorporated by reference into Part III of this Form 10-K.
<PAGE>   2
 
CONSOLIDATED NATURAL GAS COMPANY
FORM 10-K ANNUAL REPORT
For the Year Ended December 31, 1995
 
                               TABLE OF CONTENTS
 
<TABLE>
<CAPTION>
                                                                                         Page
                                                                                         ----
<S>              <C>                                                                     <C>
PART I
------
     ITEM 1.     BUSINESS
                   The Company........................................................     1
                   Governmental Regulation............................................     3
                   Capital Expenditures...............................................     3
                   Competitive Conditions.............................................     4
                   Gas Supply.........................................................     7
                   Gas Sales and Transportation.......................................    10
                   Gas Sales, Supply and Transportation Statistics....................    12
                   Market Expansion...................................................    13
                   Rate Matters.......................................................    14
                   Executive Officers of the Company..................................    16
     ITEM 2.     PROPERTIES
                   General Information on Facilities..................................    17
                   Map - Principal Facilities.........................................    18
                   Map - Exploration and Production Areas.............................    19
                   Gas and Oil Producing Activities...................................    20
     ITEM 3.     LEGAL PROCEEDINGS....................................................    22
     ITEM 4.     SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..................    22
PART II
-------
     ITEM 5.     MARKET FOR THE COMPANY'S COMMON STOCK AND RELATED
                   STOCKHOLDER MATTERS................................................    22
     ITEM 6.     SELECTED FINANCIAL DATA..............................................    23
     ITEM 7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
                   CONDITION AND RESULTS OF OPERATIONS................................    24
     ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA..........................    39
     ITEM 9.     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
                   ACCOUNTING AND FINANCIAL DISCLOSURE................................    74
PART III
--------
     ITEM 10.    DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY......................    74
     ITEM 11.    EXECUTIVE COMPENSATION...............................................    74
     ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
                   MANAGEMENT.........................................................    74
     ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.......................    74
PART IV
-------
     ITEM 14.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
                   ON FORM 8-K........................................................    74
SIGNATURES       .....................................................................    78
----------
</TABLE>
<PAGE>   3
 
CONSOLIDATED NATURAL GAS COMPANY
FORM 10-K ANNUAL REPORT
For the Year Ended December 31, 1995
 
                                     PART I
                                     ------
ITEM 1.     BUSINESS
 
THE COMPANY
 
Consolidated Natural Gas Company is a Delaware corporation organized on July 21,
1942, and a public utility holding company registered under the Public Utility
Holding Company Act of 1935 (PUHCA). It is engaged solely in the business of
owning and holding all of the outstanding equity securities of sixteen directly
owned subsidiary companies.
 
Consolidated Natural Gas Company and its subsidiaries (the Company) at December
31, 1995, are listed below. In addition to operating in all phases of the
natural gas business, the Company explores for and produces oil and provides a
variety of energy marketing services (see Note 18 to the consolidated financial
statements, page 65). At December 31, 1995, the Company had 6,600 regular
employees.
 
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
                                                                                   State of
                              Name of Company                                   Incorporation
-----------------------------------------------------------------------------------------------
<S>                                                                            <C>
CONSOLIDATED NATURAL GAS COMPANY (Parent Company)...........................       Delaware
All wholly owned subsidiaries of the Parent Company:
  Consolidated Natural Gas Service Company, Inc. (Service Company)..........       Delaware
  CNG Transmission Corporation (CNG Transmission)...........................       Delaware
  The East Ohio Gas Company (East Ohio Gas).................................         Ohio
  The Peoples Natural Gas Company (Peoples Natural Gas).....................     Pennsylvania
  Virginia Natural Gas, Inc. (Virginia Natural Gas).........................       Virginia
  Hope Gas, Inc. (Hope Gas).................................................    West Virginia
  West Ohio Gas Company (West Ohio Gas).....................................         Ohio
  CNG Producing Company (CNG Producing).....................................       Delaware
  CNG Energy Services Corporation (CNG Energy Services).....................       Delaware
  CNG Power Company (CNG Power)*............................................       Delaware
  CNG Power Services Corporation (CNG Power Services).......................       Delaware
  CNG Storage Service Company (CNG Storage).................................       Delaware
  Consolidated System LNG Company (Consolidated LNG)........................       Delaware
  CNG Research Company (CNG Research).......................................       Delaware
  CNG Coal Company (CNG Coal)...............................................       Delaware
  CNG Financial Services, Inc. (CNG Financial)..............................       Delaware
<FN>
 
*Formerly CNG Energy Company.
--------------------------------------------------------------------------------
</TABLE>
 
The principal cities served at retail by the gas distribution subsidiaries (East
Ohio Gas, West Ohio Gas, Peoples Natural Gas, Virginia Natural Gas and Hope Gas)
are: Cleveland, Akron, Youngstown, Canton, Warren, Lima, Ashtabula and Marietta
in Ohio; Pittsburgh (a portion), Altoona and Johnstown in Pennsylvania; Norfolk,
Newport News, Virginia Beach, Chesapeake, Hampton and Williamsburg in Virginia;
and Clarksburg and Parkersburg in West Virginia. At December 31, 1995, the
Company served at retail approximately 1,824,000 residential, commercial and
industrial gas sales customers in Ohio, Pennsylvania, Virginia and West
Virginia. Variations in weather conditions can materially affect the volume of
gas delivered by the distribution subsidiaries, as 98 percent of their
residential and commercial customers use gas for space heating.
 
CNG Transmission is an interstate gas transmission subsidiary that operates a
regional interstate pipeline system serving each of the distribution
subsidiaries, and nonaffiliated utility and end-user customers in
 
                                        1
<PAGE>   4
 
ITEM 1.     BUSINESS (Continued)
 
the Midwest, the Mid-Atlantic states and the Northeast. Regulatory efforts
intended to increase competition in the natural gas industry have resulted in
significant changes in the operations of CNG Transmission over the past decade.
Under Federal Energy Regulatory Commission (FERC) Order 636, interstate pipeline
companies, including CNG Transmission, were required to revise customer
contracts and service tariffs and further "unbundle" their services into
separate sales, transportation and storage transactions, with such services
offered and priced separately. Having implemented Order 636 on October 1, 1993
(see "FERC Order 636," page 34), CNG Transmission has abandoned its traditional
"bundled" sales service and offers a number of gas transportation and storage
service options, along with related services, to a broad range of customers.
Variations in weather conditions can materially affect the volume of gas
transported and stored by CNG Transmission, since a substantial portion of its
gas deliveries is ultimately used by space-heating customers. However, under the
straight fixed variable rate design prescribed by Order 636, operating results
are less influenced by changes in throughput than in the past.
 
Through its wholly owned subsidiary, CNG Iroquois, Inc., CNG Transmission holds
a 9.4 percent general partnership interest in the Iroquois Gas Transmission
System, L.P., a Delaware limited partnership that owns and operates an
interstate natural gas pipeline extending from the Canada-United States border
near Iroquois, Ontario, to Long Island, New York. The Iroquois pipeline
transports Canadian gas to utility and power generation customers in
metropolitan New York and New England.
 
CNG Producing is a gas and oil exploration and production subsidiary whose
activities are conducted primarily in the Gulf of Mexico, the southern and
western United States, the Appalachian region, and in Canada. In addition, CNG
Producing participates in several coalbed methane projects.
 
CNG Energy Services is a nonregulated energy marketing subsidiary that offers an
array of gas sales, transportation, storage and other services that can be
arranged separately or in various combinations to meet the individual needs of
customers. CNG Energy Services markets Company-owned gas production and also
offers the equivalent of the "bundled" services previously provided by CNG
Transmission prior to Order 636.
 
CNG Power develops new business opportunities in energy-related markets. It
invests in and develops independent power producer projects and conducts a gas
liquids business. CNG Power holds a 34% limited partnership interest in Lakewood
Cogeneration, L.P. (Lakewood Partnership), which operates a 237-megawatt
cogeneration facility in Lakewood, New Jersey.
 
CNG Power Services is a power marketing subsidiary with FERC approval to
purchase and resell electricity at market-based rates. CNG Lakewood, Inc., a
wholly owned subsidiary of CNG Power Services, owns a 1% general partnership
interest in the Lakewood Partnership.
 
CNG Storage is engaged in providing natural gas storage facilities and a wide
range of storage-related services to affiliates and other customers, including
the sale or lease of base gas, and the sale, lease or brokerage of gas storage
capacity obtained from third parties.
 
Consolidated LNG was organized to import and regasify liquefied natural gas
(LNG) for sale to CNG Transmission. However, Consolidated LNG ended its
involvement in LNG operations in 1982 and is currently recovering its
undepreciated investment in LNG-related facilities, plus carrying charges and
taxes, through a FERC-approved amortization surcharge.
 
CNG Research administers proprietary research activities. Amounts spent on
research activities in the calendar years 1993 through 1995 by all the
subsidiary companies were not material.
 
CNG Coal owns coal reserves and a related plant site. Most of these coal
reserves are located in Greene County, Pennsylvania, principally in the
Sewickley and Pittsburgh coal seams. In the second quarter of 1995, the Company
recognized a pretax charge of $31.3 million in connection with a write-down of
the value of these coal properties. In addition, the Company has entered into a
letter of intent for the
 
                                        2
<PAGE>   5
 
ITEM 1.     BUSINESS (Continued)
 
proposed sale of the properties to a third party (see Note 3 to the consolidated
financial statements, page 50).
 
Service Company is a subsidiary service company, authorized by the Securities
and Exchange Commission (SEC) under the PUHCA. It advises and assists the other
subsidiary companies on administrative and technical matters and manages
centralized activities and facilities for their benefit. It also provides
services to the Parent Company.
 
CNG Financial was formed to engage in certain financing transactions, but has
not yet engaged in any such transactions.
 
GOVERNMENTAL REGULATION
 
The Company is subject to regulation by the SEC pursuant to the PUHCA. After an
in-depth study of the PUHCA in the context of fundamental changes in the energy
industry over the past decade, the SEC's Division of Investment Management
issued a report in June 1995 on the regulation of public utility holding
companies. This report contains recommendations for legislative action,
including repeal of the PUHCA with more oversight responsibility borne by the
FERC and state commissions. The report also proposes reform to remove a
substantial portion of the administrative burden inherent in the current PUHCA
regulatory policies and procedures. The SEC initiated action in 1995 to
implement such reform.
 
CNG Transmission and Consolidated LNG are "natural-gas companies" subject to the
Natural Gas Act of 1938, as amended. CNG Transmission's interstate
transportation and storage activities are regulated under such Act and are
conducted in accordance with tariffs and service agreements on file with the
FERC. The distribution subsidiaries are subject to regulation by the respective
utility commissions in the states within which they operate. CNG Power Services,
a public utility as defined by section 201 of the Federal Power Act, is subject
to FERC regulation.
 
Certain subsidiaries are subject to various provisions of the five statutes
which are referred to as the National Energy Act of 1978. One of these statutes,
the National Energy Conservation Policy Act, requires utilities to offer home
energy audits and other assistance to residential customers.
 
The Natural Gas Pipeline Safety Act of 1968 (which, among other things,
authorizes the establishment and enforcement of federal pipeline safety
standards) subjects the interstate pipeline of CNG Transmission to the safety
jurisdiction of the Department of Transportation. Intrastate facilities remain
within the safety jurisdiction of the state regulatory agencies, presuming
compliance by such agencies with certain prerequisites contained in such Act.
 
The Company is subject to the provisions of various federal laws dealing with
the protection of the environment. CNG Transmission and certain of the
distribution subsidiaries are subject to the Federal Clean Air Act and the
Federal Clean Air Act Amendments of 1990 which added significantly to the
existing requirements established by the Federal Clean Air Act. In addition, the
subsidiary companies are subject to the environmental laws and regulations of
state and local governmental authorities in the areas within which the
subsidiaries have operations or facilities. Reference is made to Note 16 to the
consolidated financial statements, page 63, for additional information on
environmental-related matters.
 
CAPITAL EXPENDITURES
 
The Company's current capital budget for 1996 is estimated at $455.2 million, a
4 percent increase over the $439.4 million spent in 1995. The 1996 budget
reflects increased expenditures for the nonregulated and transmission operations
and a reduction in spending for the distribution operations.
 
Expenditures for the exploration and production operations are estimated to be
$180.6 million in 1996, up from $176.8 million in 1995. The higher amount in
1996 includes funds for development of Neptune at Viosca Knoll 826, the
Company's second deep-water project in the Gulf of Mexico. Transmission
 
                                        3
<PAGE>   6
 
ITEM 1.     BUSINESS (Continued)
 
expenditures in 1996 are budgeted at $89.3 million, up from $81.6 million spent
in 1995. Distribution operations spending in 1996 is expected to be $147.6
million, compared with $160.5 million in 1995. Transmission and distribution
operations expenditures will primarily be limited to spending for enhancements
and improvements in the pipeline system and related facilities. Planned
expenditures for the energy marketing services component in 1996 total $33.2
million and include funds for the development, through partnerships with other
energy companies, of offshore gas and oil gathering systems for two production
areas in the Gulf of Mexico. The 1996 capital budget also includes $4.5 million
allocated to "corporate and other," including expenditures to upgrade
information systems technology. The capital budget will be reviewed during the
year and is subject to revision. (See "Capital Spending," page 37.)
 
       RESTRICTIONS UNDER CERTAIN DEBT AGREEMENTS
 
At December 31, 1995, the Company had senior debentures outstanding under a 1971
indenture between the Company and Chemical Bank, as trustee (the 1971
Indenture). The 1971 Indenture contains covenants which limit, among other
things, the incurrence of funded debt. As a result of charges in 1995 for
workforce reduction costs and write-downs of gas and oil producing properties
and coal properties, the Company's ability to issue funded debt is expected to
be restricted through May 1996. Reference is made to Note 13 to the consolidated
financial statements, page 61, for further details regarding this restriction.
 
COMPETITIVE CONDITIONS
 
Various regulatory and market trends have combined to increase competition for
the Company in recent years, and for the gas industry in general. The factors
affecting the Company include: regulatory efforts, such as the FERC's various
initiatives to increase competition in the industry; the overall availability of
gas nationwide at relatively low prices; competition from local producers and
other sellers and brokers of gas for the retail and wholesale markets; expansion
of competition among distribution companies for industrial and commercial
customers; competition with existing and proposed pipelines, and projects to
import gas from Canada and other foreign countries; and competition with other
energy forms, such as electricity, fuel oil and coal.
 
       RESTRUCTURING OF INTERSTATE PIPELINE INDUSTRY
 
Similar to previous FERC actions to enable more direct access to gas supplies
and open access to pipeline transportation systems, Order 636 has significantly
increased competition in the natural gas industry. In the restructured
marketplace, local gas utilities and large-volume end users, including former
pipeline sales customers, now bear all the responsibilities and risks for
arranging the procurement of their gas supplies and contracting with pipelines
to transport purchases. Other significant changes required by Order 636 included
a basic change in the way rates are designed. Under the new rate design, return
on equity and related income taxes are recovered as part of a fixed monthly
charge. Previously, these costs were recovered through usage or commodity rates.
CNG Transmission implemented Order 636 on October 1, 1993 (see "FERC Order 636,"
page 34) and thereby abandoned its traditional "bundled" sales service. CNG
Transmission now offers a number of gas transportation and storage service
options, along with related services, to a broad range of customers.
 
The restructuring of the interstate natural gas pipeline industry has also
affected the distribution subsidiaries. Industrial and large commercial gas
users now purchase a large portion of their gas supplies directly from
producers, from marketers, or on the spot market. However, the distribution
subsidiaries have, for the most part, been able to retain these customers by
providing transportation service for such supplies. The most significant effect
on local distribution companies of Order 636 has been on their gas supply
procurement and storage practices. Since bundled pipeline sales service is no
longer available,
 
                                        4
<PAGE>   7
 
ITEM 1.     BUSINESS (Continued)
 
these companies now bear all the responsibilities and risks for arranging the
acquisition, delivery and storage of their own gas supplies. However, as a
result of previous FERC initiatives, the distribution subsidiaries have been
managing a part of their own gas supplies for a number of years. Therefore, the
transition to the more competitive environment under Order 636 did not have a
significant impact on their operations. Additionally, as a result of Order 636,
storage facilities owned and operated by the distribution and transmission
operations as well as storage capacity acquired have become even more important
factors in gas supply management.
 
As a result of the restructuring under Order 636, gas producers throughout the
industry, including CNG Producing, are faced with a more diverse and active
market with purchasers seeking to balance the advantage of lower-cost spot
market supplies with the security of higher-priced, longer-term contracts. The
continued emergence of gas and energy marketing firms has added to the
competition for CNG Producing. As a result, effective January 1, 1995, CNG
Energy Services became the primary marketing agent for all of the Company's
nonregulated gas production (see "Energy Marketing Services," page 7).
 
       DISTRIBUTION
 
The distribution subsidiaries generally operate in long-established service
areas and have extensive facilities already in place. Growth in the Company's
traditional service areas in Ohio, Pennsylvania and West Virginia is limited in
that natural gas is already the fuel of choice for heating and for most
significant industrial applications. These areas have experienced minimal
population growth in the past, and almost all customers have become more energy
efficient, resulting in lower gas usage per customer. In addition, the economies
of these areas, which were formerly based mainly on heavy industry, have
diversified with increased emphasis on high technology and service oriented
firms.
 
However, opportunities for growth in the distribution operations are expected to
continue at Virginia Natural Gas. This subsidiary offers the potential for
future growth through its expanding service territory and the prospect of
conversion of space-heating customers and commercial and industrial applications
to gas. The completion in 1992 of the intrastate pipeline in Virginia has
provided Virginia Natural Gas and its customers with new gas supply sources
through access to the Company's transmission and storage facilities, and has
afforded additional opportunities for growth in both gas sales and
transportation, especially in the power generation markets.
 
The Federal Clean Air Act may also provide opportunities for increased
throughput in the Company's distribution markets. The Company is promoting the
use of natural gas as a means for industrial customers and electric generators
to reduce emissions. The Federal Clean Air Act and the more recent Energy Policy
Act of 1992 contain a number of provisions relating to the use of alternative
fuel vehicles. The Company is participating in various programs to demonstrate
the advantages and environmental benefits of natural gas powered vehicles.
 
Competition in the markets served by the distribution subsidiaries continues to
increase. As the gas industry has restructured and government regulations have
changed, a marketplace has evolved with new and traditional competitors--the
usual oil and electric companies, other gas companies, local producers seeking
to gain direct access to the Company's customers, and gas brokers and dealers
seeking to supplant supplies with spot market gas. Natural gas faces price
competition with other energy forms, and certain of the distribution companies'
industrial customers have the ability to switch to fuel oil or coal if desired.
In addition, competition is increasing among local distribution companies to
provide gas sales and transportation services to commercial and residential
customers. Local distribution companies operate in what are essentially dual
markets--a traditional utility market, where a utility has an obligation to
provide service and offers a "bundled" package of services to all customers; and
a "contract" market, where obligations are defined by contract terms and large
customers can elect individually or in various combinations whatever gas
supplies, storage and/or transportation services they require. The Company has
responded to this competitive environment by offering an expanded range of
services to its customers. The distribution subsidiaries now routinely provide a
variety of firm and interruptible services,
 
                                        5
<PAGE>   8
 
ITEM 1.     BUSINESS (Continued)
 
including gas transportation, storage, supply pooling and balancing, and
brokering, to industrial and commercial customers.
 
       TRANSMISSION
 
CNG Transmission operates a regional interstate pipeline system with the
principal pipeline and storage facilities located in Ohio, Pennsylvania, West
Virginia and New York. As a result of deregulation, the role of the transmission
operations has changed from primarily that of a merchant, or wholesaler, of gas
to one that provides a wide range of services. Although CNG Transmission no
longer provides its traditional bundled sales service, it continues to offer gas
transportation, storage and related services to its affiliates, as well as to
utilities and end users in the Northeast, Mid-Atlantic and Midwest regions of
the country.
 
The changing regulatory policies have provided CNG Transmission and other
pipeline companies with unique opportunities for expansion. CNG Transmission has
directed its expansion efforts toward potential high-volume, weather-sensitive
markets and areas with growing power generation needs, with particular emphasis
on Northeast and East Coast markets. CNG Transmission's large underground
storage capacity and the location of its gridlike pipeline system as a link
between the country's major gas pipelines and large markets on the East Coast
have been key factors in the success of these expansion efforts.
 
CNG Transmission competes with domestic as well as Canadian pipeline companies
and gas marketers seeking to provide or arrange transportation, storage and
other services for customers. Also, certain end users have the ability to switch
to fuel oil or coal if desired. Although competition is based primarily on
price, the range of services that can be provided to customers is also an
important factor. The combination of capacity rights held on certain longline
pipelines, a large storage capability and the availability of numerous receipt
and delivery points along its own pipeline system, enables CNG Transmission to
tailor its services to meet the individual needs of customers.
 
With CNG Transmission's implementation of Order 636, former wholesale sales
customers now have the responsibility and risk inherent in contracting for their
own gas supplies. However, since customers have greater access to the Company's
pipeline and storage capacity, both increased gas transportation and storage
service have offset the impact of CNG Transmission's abandonment of its
traditional sales service.
 
       EXPLORATION AND PRODUCTION
 
Exploration and production operations are conducted by CNG Producing in several
of the major gas and oil producing basins in the United States, both onshore and
offshore. In this highly competitive business, the Company competes with a large
number of entities ranging in size from large international oil companies with
extensive financial resources to small, cash flow-driven independent producers.
 
CNG Producing faces significant competition in the bidding for federal offshore
leases and in obtaining leases and drilling rights for onshore properties. Since
CNG Producing is the operator of a number of properties, it also faces
competition in securing drilling equipment and supplies for exploration and
development. From the production perspective, the marketing of gas and oil is
highly competitive with price being the most significant factor. Effective
January 1, 1995, CNG Energy Services became the primary marketing agent for all
of the Company's nonregulated gas production. When the economics warrant, the
Company attempts to sell its gas production under long-term contracts to
customers such as electric power generators and others that require a secure
source of supply. These arrangements generally command a premium over spot
market prices. Further, the deliverability of gas produced is also influenced by
competition for downstream pipeline transportation capacity. In response to the
unbundling of sales services previously offered by pipelines, CNG Producing and
CNG Energy Services have taken actions to expand and diversify the Company's
customer base. CNG Energy Services continues to
 
                                        6
<PAGE>   9
 
ITEM 1.     BUSINESS (Continued)
 
develop new marketing strategies and contracts to address customer needs for
intermediate and long-term gas supplies as well as other services in the
post-Order 636 era.
 
The exploration for and production of gas and oil is subject to various federal
and state laws and regulations which may, among other things, limit well
drilling activity and volumes produced. Changes in these laws and regulations
can impact the exploration and production operations.
 
       ENERGY MARKETING SERVICES
 
The Company's energy marketing services operations, comprised of CNG Energy
Services, CNG Power, CNG Power Services and CNG Storage, are engaged in a
variety of energy-related activities in highly competitive markets. These
activities, which were under a single management team in 1995, include fuel
management, gas trading, energy price risk management, pipeline capacity and
storage management, power marketing and electric generation.
 
Energy marketing services competes with the marketing operations of both
independent and major energy companies in addition to electric utilities,
independent power producers, local distribution companies, and various energy
brokers. As a result of the continuing efforts to deregulate both natural gas
and electric utility operations, the economic differences among different forms
of energy are expected to be reduced in the future. Competition is based largely
upon pricing, availability and reliability of supply, technical and financial
capabilities, regional presence and international experience. In addition,
several companies have combined resources via merger or strategic alliances to
enhance their ability to meet customer demands both domestically and
internationally. Reference is made to "International Activities," page 13,
regarding the Company's actions in this area.
 
GAS SUPPLY
 
       GENERAL INFORMATION
 
The Company's gas supply is obtained from various sources including: purchases
from major and independent producers in the Southwest and Midwest regions;
purchases from local producers in the Appalachian area; purchases from gas
marketers; purchases on the spot market; production from Company-owned wells in
the Appalachian area, the Southwest, and the Midwest; and withdrawals from the
Company's underground storage fields.
 
Regulatory actions, economic factors, and changes in customers and their
preferences over the past several years have reshaped the Company's gas sales
markets. A significant number of industrial customers and many commercial
customers now purchase a large portion of their gas supplies from producers,
marketers, or on the spot market, and contract with the transmission and
distribution subsidiaries for transportation and other services. Since these
customers are less reliant on the distribution subsidiaries for sales service,
the volume of gas that these subsidiaries must obtain to meet sales requirements
has been reduced. Since CNG Transmission no longer provides traditional sales
service, its former sales customers, including the distribution subsidiaries,
have the responsibility and risk for obtaining their own gas supplies. Overall,
the Company's gas supply requirements have grown due largely to the increase in
nonregulated gas sales by CNG Energy Services.
 
The Company's available gas supply in 1995 was again in a surplus
position--where available supplies exceed sales requirements. Considering the
Company's large storage capacity, the volumes obtainable under its gas purchase
and gas supply contracts, Company-owned gas reserves, and assuming the future
availability of spot market gas, the Company believes that supplies will be
available to meet sales requirements for several years. Gas supply statistics
for the past five years are on page 12.
 
                                        7
<PAGE>   10
 
ITEM 1.     BUSINESS (Continued)
 
       GAS PURCHASED
 
Purchased gas volumes were 771.1 billion cubic feet (Bcf) in 1995, representing
86 percent of the Company's total 1995 gas supply of 897.5 Bcf. Spot market and
short-term purchases were 701.8 Bcf, or about 78 percent of the total 1995
supply. Volumes purchased under contracts with Appalachian area producers
totaled 69.3 Bcf, or 8 percent of the 1995 supply.
 
In response to the regulatory and market changes over the past several years,
including Order 636, the Company converted its long-term gas purchase contracts
with interstate pipelines to firm transport contracts. As a result, gas volumes
purchased from the pipeline companies have been eliminated and replaced, in
large part, with contract volumes purchased directly with producers and
marketers.
 
While spot market gas supplies have historically been obtained at lower prices,
the availability and price of such supplies to distribution companies can be
severely impacted by sudden market swings in supply and demand. The distribution
subsidiaries now must weigh the benefits of generally lower-cost spot market
purchases with the security of longer-term contract arrangements. To ensure a
secure supply in the post-Order 636 market, the distribution subsidiaries have
purchased a larger portion of their gas supplies directly from producers on a
firm basis. However, spot market gas will continue to be part of the Company's
supply mix, particularly for CNG Energy Services.
 
Gas purchased from producers and on the spot market is delivered to the
distribution subsidiaries using the firm transport capacity contracted for on
interstate pipelines. At December 31, 1995, the subsidiaries had 415 Bcf of firm
transport capacity on upstream pipelines, yielding deliveries of up to 1.1 Bcf
of gas a day. These upstream pipelines include Tennessee Gas Pipeline Company,
Panhandle Eastern Pipe Line Company, Texas Eastern Transmission Corporation
(Texas Eastern), ANR Pipeline Company, Texas Gas Transmission Corporation,
Transcontinental Gas Pipe Line Corporation and Columbia Gas Transmission
Corporation.
 
       GAS STORAGE
 
The Company's underground storage complex plays an important part in balancing
gas supply with sales demand and is essential to servicing the Company's large
volume of space-heating business. The Company operates 26 underground gas
storage fields located in Ohio, Pennsylvania, West Virginia and New York. The
Company owns 21 of these storage fields and has joint-ownership with other
companies in 5 of the fields. The total designed capacity of the storage fields
is approximately 885 Bcf. The Company's share of the total capacity is about 669
Bcf. About one-half of the total capacity is base gas which remains in the
reservoirs at all times to provide the primary pressure which enables the
balance of the gas to be withdrawn as needed.
 
CNG Transmission operates 719 Bcf of the total designed storage capacity and
owns 503 Bcf of the Company's capacity. CNG Transmission utilizes a large
portion of its turnable capacity to provide approximately 252 Bcf of gas storage
service for others. This service is provided to pipelines and utilities whose
primary service areas are along the East Coast. CNG Transmission also provides
storage service to affiliates, end users and to many of its former wholesale gas
sales customers.
 
Two of the distribution subsidiaries, East Ohio Gas and Peoples Natural Gas, own
and operate the remaining 166 Bcf of storage capacity. In addition to owning
their own storage, these companies, as well as most of the other subsidiaries,
have ready access to a portion of the storage capacity operated by CNG
Transmission. Certain distribution subsidiaries also have capacity available in
storage fields owned by others. In the post-Order 636 environment, available
storage capacity is an important element in the effective management of both gas
supply and pipeline transport capacity.
 
The Company controls other acreage in the Appalachian area suitable for the
development of additional storage facilities which would enable further
expansion of capacity to meet possible future storage needs.
 
                                        8
<PAGE>   11
 
ITEM 1.     BUSINESS (Continued)
 
       GAS AND OIL PRODUCING ACTIVITIES
 
Over the past several years, the exploration and production operations have been
affected by the generally adverse conditions in the industry. The effects of
continued warm weather, the lingering gas oversupply situation, and low gas and
oil wellhead prices have all contributed to a difficult operating environment.
However, the level of capital spending on exploration and production operations
has increased during the past three years, and is expected to increase again in
1996, reflecting the Company's longer-term commitment to these operations. Part
of the Company's strategy for its exploration and production operations is to
better balance offshore and onshore production, and to increase the oil portion
of total production. The Company will continue to develop its second deep-water
project in the Gulf of Mexico at Viosca Knoll 826, in addition to onshore and
other offshore projects.
 
The Company's gas wellhead prices in 1995 averaged $1.89 a thousand cubic feet
(Mcf), down from $2.16 in 1994. Consistent with prices nationwide, the Company's
gas wellhead prices in 1995 were below prior year levels for most of the period.
The Company's average gas wellhead prices are generally higher and less volatile
than industry spot prices since its average price reflects a mix of longer-term
contracts. However, due to market-based pricing mechanisms under many of the
contracts, the Company's gas prices generally follow industry trends. The
average oil wellhead price in 1995 increased to $16.04 a barrel, compared with
$14.45 in 1994, consistent with the general increase in world oil prices.
 
The Company's total gas production in 1995 was 107.2 Bcf, down from 119.5 Bcf in
1994. Oil production was 3.1 million barrels, down 6 percent from 3.4 million
barrels in 1994. The low gas prices that prevailed nationwide during most of
1995 were the basis for the Company's decision to shut in a portion of its
offshore production at various times of the year which, in addition to normal
declines at certain properties, resulted in lower gas production for the year.
However, the lower oil production during 1995 was due largely to normal
production declines at older properties.
 
During 1995, CNG Producing participated in the drilling of 53 gross wells (26
net), compared with 81 gross wells (35 net) drilled in 1994. The following table
sets forth 1995 drilling activity by region:
 
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
                                                                       Gross Wells Drilled
                                                                   Exploratory     Development
----------------------------------------------------------------------------------------------
<S>                                                                   <C>             <C>
Onshore (Southwest and West)....................................         6              11
Gulf of Mexico..................................................        15               6
Appalachian Region..............................................        --               2
Canada..........................................................        --              13
                                                                       ---             ---
     Total......................................................        21              32
                                                                       ===             ===

----------------------------------------------------------------------------------------------
</TABLE>
 
Of the total 53 wells drilled in 1995, 38 were successful, a 72 percent success
rate. Of the 21 exploratory wells drilled, 7 were successful, including finds at
Main Pass 222/223 and West Cameron 580 off the Louisiana coast, and High Island
312, offshore Texas.
 
Total Company-owned proved gas reserves at year-end were 1,041 Bcf, up from 972
Bcf at the end of 1994. Proved oil reserves were 45.8 million barrels, compared
with 46.5 million barrels in 1994. East Ohio Gas sold all of its remaining gas
and oil reserves during 1995. CNG added 203 Bcf equivalent of gas and oil
reserves in 1995, equal to 167 percent of total production. (See "Company-Owned
Reserves," page 20.)
 
Natural gas production began in January 1996 at Popeye, a deep-water natural gas
discovery in the Green Canyon area of the Gulf of Mexico. The field is producing
over 120 million cubic feet of gas per day from two wells flowing through a
state of the art subsea facility developed to produce gas 2,000 feet below sea
level. CNG Producing's interest in this property is 37.5 percent. Other
participants in the joint venture are Mobil Oil Exploration and Producing
Southeast and BP Exploration Inc.
 
                                        9
<PAGE>   12
 
ITEM 1.     BUSINESS (Continued)
 
Development will continue in 1996 at Neptune, a deep water oil discovery at
Viosca Knoll 826. This project, in which the Company holds a 50 percent
interest, added proved reserves equivalent to 190 Bcf of gas in 1994,
representing the largest single addition to the Company's reserves in its
history. Facilities are being designed with Oryx Energy Company, the operating
partner, to produce up to 25,000 barrels of oil and 30 million cubic feet of
natural gas a day. Production is expected to begin in early 1997. Neptune will
make use of an innovative floating production facility called a Spar, a
700-foot-long cylindrical structure that will be towed to the site, turned on
end and anchored to the sea floor with cables. This is the first time a Spar
will be used in the Gulf of Mexico as a production platform. Participation in
the Popeye and Neptune projects is providing the Company access to new
technologies and the experience necessary to better evaluate future deep-water
opportunities.
 
The Company drilled 2 wells in the Appalachian Region during 1995. Gas from this
area normally commands a higher price because of its location in proximity to
major gas markets. However, due to deregulation and the increased availability
of pipeline capacity over the past few years, this location differential has
lessened somewhat. The Company plans to continue production from these
properties and to maintain its strong acreage position in the Appalachian
Region, and may seek to acquire additional properties in this area that meet the
Company's longer-term strategy. Selected Appalachian properties were sold during
1995, but the acreage and reserves were not material.
 
In the second quarter of 1995, CNG Energy Services and Centana Energy
Corporation (Centana) announced plans to build a gas and oil gathering pipeline
system to serve two production areas in the Gulf of Mexico--Main Pass and Viosca
Knoll. Later in 1995, a third partner, Amoco Pipeline, was added to the oil
gathering project. The system will have the capacity to carry 300 million cubic
feet per day of natural gas, 5,000 barrels per day of condensate and 130,000
barrels per day of crude oil. Construction of the pipeline system began in 1995
and is scheduled to be completed in 1996. Centana will operate the natural gas
and condensate lines and Amoco Pipeline will operate the oil pipeline. The
estimated cost of the projects is $89 million, with CNG Energy Services' share
amounting to approximately $37 million.
 
CNG Producing was the successful bidder on 8 leases offered in the federal
government's Gulf of Mexico lease sales in 1995, acquiring 8 blocks off the
coast of Louisiana. At year-end 1995, the Company held 2.0 million net acres of
exploration and production properties, down from 2.4 million at year-end 1994.
The Company's lease holdings include about 1.4 million net acres in the
Appalachian area, 308,800 in the offshore Gulf of Mexico, and 374,200 in the
inland areas of the Southwest, Gulf Coast and West. The Company holds a 21
percent interest in heavy oil properties in Alberta, Canada. Proved reserves
associated with the Canadian properties approximated 1 Bcf of gas and 5.8
million barrels of oil at December 31, 1995. On an energy-equivalent basis,
these reserves represent about 3 percent of Consolidated's total proved reserves
at that date.
 
The Company will continue to review its property inventory during 1996, and
sales of selected properties are possible depending on economic conditions.
 
GAS SALES AND TRANSPORTATION
 
Total gas sales in 1995 were 846 Bcf, up 37 percent from the 618 Bcf sold in
1994. Transportation volumes were 750 Bcf in 1995, a 3 percent increase from the
725 Bcf transported in 1994. (Five-year statistics are on page 12.)
 
       GAS SALES CUSTOMERS
 
At December 31, 1995, the Company's distribution subsidiaries served almost 1.7
million residential customers, about 126,000 commercial customers and about
1,700 industrial customers in Ohio, Pennsylvania, Virginia and West Virginia.
 
                                       10
<PAGE>   13
 
ITEM 1.     BUSINESS (Continued)
 
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------
                                      Residential
Customers               Total        and Commercial      Industrial      Wholesale      Nonregulated
----------------------------------------------------------------------------------------------------
<S>                   <C>             <C>                 <C>              <C>             <C>
December 31,
   1995               1,824,497        1,822,253           1,736            12              496
   1994               1,799,649        1,797,433           1,697            14              505
   1993               1,777,157        1,774,922           1,688            31              516
   1992               1,759,284        1,757,139           1,694            32              419
   1991               1,737,947        1,735,803           1,698            31              415
 
----------------------------------------------------------------------------------------------------
</TABLE>
 
       RESIDENTIAL AND COMMERCIAL SALES
 
Sales of gas to residential customers in 1995 were 212 Bcf, up 6 Bcf from 1994,
while sales to commercial customers were 70 Bcf in 1995, up 1 Bcf compared to
1994. Residential and commercial gas sales volumes increased during 1995
reflecting colder weather and the net addition of about 24,800 customers. The
weather in the Company's retail service areas in 1995 was 2 percent colder than
1994, but was 1 percent warmer than normal.
 
       INDUSTRIAL SALES
 
Industrial sales in 1995 were 7 Bcf, down 2 Bcf compared to 1994. Due to both
availability and price, many industrial users buy gas directly from producers,
from marketers, or on the spot market, and contract with the subsidiary
companies for transportation service. Total gas deliveries (sales and
transportation) to industrial customers were 138 Bcf in 1995, compared with 130
Bcf in 1994.
 
       WHOLESALE SALES
 
With CNG Transmission's abandonment of its traditional sales service pursuant to
FERC Order 636, wholesale sales volumes are no longer significant for the
Company. Total sales volumes were .3 Bcf in 1995, the same level as in 1994.
 
       NONREGULATED SALES
 
Nonregulated gas sales in 1995 were 557 Bcf, up from 333 Bcf in 1994. Gas sales
by CNG Energy Services were 523 Bcf, compared to 190 Bcf in 1994. Volumes
related to gas brokering activity were 25 Bcf in 1995, down from 54 Bcf in 1994.
Sales of Company-produced gas, primarily by CNG Producing, to nonaffiliates were
9 Bcf, compared with 89 Bcf in 1994. Effective January 1, 1995, CNG Energy
Services became the primary marketing agent for all of the Company's
nonregulated gas production.
 
       GAS TRANSPORTATION
 
Total transportation volumes in 1995 were 750 Bcf, up from 725 Bcf in 1994.
First quarter 1995 transport volumes were lower than the prior year due to
warmer weather in that period, while transport volumes were up for the balance
of 1995 compared to 1994. Total volumes transported by the distribution
subsidiaries for commercial, industrial and off-system customers were up 14 Bcf
over 1994, as transportation volumes for industrial customers were up 10 Bcf
compared to the prior year.
 
                                       11
<PAGE>   14
 
ITEM 1.     BUSINESS (Continued)
 
GAS SALES, SUPPLY AND TRANSPORTATION STATISTICS
(Excludes affiliated transactions)
 
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------
Years Ended December 31,                1995         1994         1993         1992         1991
------------------------------------------------------------------------------------------------
<S>                                 <C>          <C>          <C>          <C>          <C>
GAS SALES REVENUES (MILLIONS)
Regulated
  Residential and commercial....    $1,560.1     $1,628.3     $1,595.1     $1,428.7     $1,373.1
  Industrial....................        32.6         45.8         55.4         50.0         46.0
  Wholesale.....................         4.7          5.2        422.7        190.8        426.8
Nonregulated....................       997.7        723.6        541.8        282.0        237.0
                                    --------     --------     --------     --------     --------
       Total....................    $2,595.1     $2,402.9     $2,615.0     $1,951.5     $2,082.9
                                    ========     ========     ========     ========     ========
AVERAGE SALES RATES PER MCF
Regulated
  Residential and commercial....    $   5.53     $   5.91     $   5.60     $   5.09     $   5.25
  Industrial....................        4.49         4.89         4.43         4.00         4.09
  Wholesale.....................           *            *         5.24            *         4.49
Nonregulated....................        1.79         2.17         2.40         2.10         2.01
       Weighted average.........    $   3.07     $   3.89     $   4.33     $   4.35     $   4.29
                                    ========     ========     ========     ========     ========
GAS REQUIREMENTS (BCF)
Regulated gas sales
  Residential and commercial....       282.3        275.3        285.0        280.7        261.7
  Industrial....................         7.3          9.4         12.5         12.5         11.2
  Wholesale.....................          .3           .3         80.7         21.2         95.0
Nonregulated gas sales..........       556.6        332.8        226.0        134.4        118.1
                                    --------     --------     --------     --------     --------
       Total sales..............       846.5        617.8        604.2        448.8        486.0
Used and unaccounted for........        51.0         48.3         44.0         51.7         34.5
                                    --------     --------     --------     --------     --------
       Total requirements.......       897.5        666.1        648.2        500.5        520.5
                                    ========     ========     ========     ========     ========
GAS SUPPLY (BCF)
Purchased gas...................       771.1        559.6        485.2        370.6        377.2
Storage (input) withdrawal......        19.2        (13.0)        33.5          1.9         10.5
Gas produced
  Gulf region...................        68.3         76.4         81.6         78.9         84.2
  Appalachian area..............        27.2         27.8         29.4         33.1         35.3
  Other areas...................        11.7         15.3         18.5         16.0         13.3
                                    --------     --------     --------     --------     --------
       Total produced...........       107.2        119.5        129.5        128.0        132.8
                                    --------     --------     --------     --------     --------
       Total supply.............       897.5        666.1        648.2        500.5        520.5
                                    ========     ========     ========     ========     ========
PURCHASED GAS COSTS
  (MILLIONS)**..................    $1,611.9     $1,375.8     $1,349.5     $1,132.1     $1,093.6
                                    ========     ========     ========     ========     ========
AVERAGE PURCHASE RATES PER
  MCF**.........................    $   2.09     $   2.46     $   2.78     $   3.05     $   2.90
                                    ========     ========     ========     ========     ========
GAS TRANSPORTATION
Revenues (Millions).............    $  333.2     $  293.7     $  222.5     $  201.0     $  154.9
                                    ========     ========     ========     ========     ========
Gas Transported (Bcf)...........       749.8        724.9        587.5        613.1        446.7
                                    ========     ========     ========     ========     ========
<FN>
 
------------------------------------------------------------------------------------------------
 * Demand charges and low sales volumes produce an average rate which is not
   meaningful.
** Includes transportation charges.
</TABLE>
 
                                       12
<PAGE>   15
 
ITEM 1.     BUSINESS (Continued)
 
MARKET EXPANSION
 
In recent years the Company has pursued a broad program designed to expand its
interstate pipeline system and extend its marketing territory. The Company's
principal objective has been to build long-term supply relationships with
customers in the growing markets at the perimeter of its system, markets which
offer opportunities for growth in throughput due to their increasing demand for
energy. The Company has concentrated its transmission expansion efforts toward
potentially high-volume, weather sensitive markets and areas with growing power
generation needs located primarily in the Northeast and along the East Coast.
These markets are particularly attractive in that gas space heating is not yet
as widely used in these areas as in the Company's traditional service areas of
western Pennsylvania, eastern Ohio, West Virginia and upstate New York. Because
of its large gas storage capacity and the location of its gridlike pipeline
system in close proximity to these markets, the Company has an opportunity to be
an important gas supplier to utilities with growing space-heating markets and
for customers seeking an environmentally clean, efficient fuel for electric
generation.
 
       PIPELINE EXPANSION
 
CNG Transmission and Texas Eastern have joint plans to provide additional
services to certain customers in the Northeast, Mid-Atlantic and Southeast
markets. CNG and Texas Eastern will file companion applications with the FERC to
obtain the required federal certification. The project, known as the Seasonal
Service Expansion Project (formerly the "WinterNet" project), would provide 150
million cubic feet per day of natural gas service to meet the winter season and
peak needs of these customers. Project facilities would include additional
pipeline capacity along CNG Transmission's and Texas Eastern's pipeline systems,
access to salt-cavern storage, and additional compression on CNG Transmission's
system. If approved by the FERC, the project would be phased in over a four-year
period beginning in 1997. Facility construction on CNG Transmission's system is
projected to cost about $55 million.
 
       ELECTRIC POWER MARKETING
 
During 1995, CNG Power Services commenced wholesale sales of electricity at
market-based rates and joined the Western Systems Power Pool (the Pool), a
trading organization of 120 companies that buy and sell electric power at tariff
rates set by the FERC. Currently, the Pool is able to trade wholesale
electricity from eastern Tennessee to the Pacific Ocean and is expected to
expand into the southern United States. CNG Power Services is also a member of
four of the nine districts of the North American Electric Reliability Council,
which serves to coordinate planning and power transmission operations. In
February 1996, the Company announced the opening of offices in Atlanta, Georgia
and Portland, Oregon to serve the wholesale and emerging retail electricity
markets in the Southeast and West Coast regions of the United States.
 
       INTERNATIONAL ACTIVITIES
 
In November 1994, CNG Energy Services formed a marketing alliance with two
Canadian firms, Hydro-Quebec and Noverco. The alliance offers energy services to
customers throughout the northeastern and midwestern United States and eastern
Canada. In June 1995, the companies signed an agreement to create a
partnership--the Energy Alliance Partnership--to conduct alliance business. This
agreement is subject to SEC and other regulatory approvals.
 
In November 1995, the Company announced the formation of a strategic alliance
with EnergyAustralia (formerly MetNorth Energy), Australia's largest electric
utility, to assist EnergyAustralia in developing its natural gas marketing
capabilities and to jointly identify and develop energy infrastructure projects
in Australia and Asia.
 
                                       13
<PAGE>   16
 
ITEM 1.     BUSINESS (Continued)
 
In January 1996, the Company formed a new subsidiary, CNG International
Corporation (CNG International). The purpose of CNG International is to engage
in energy-related activities outside the United States, including activities
under the EnergyAustralia alliance. The financing of CNG International is
subject to SEC approval.
 
       ADDITIONAL USES FOR NATURAL GAS
 
During 1995, the Company continued its involvement with a number of gas burning
technologies that provide opportunities to improve customer efficiency while
promoting the use of natural gas in markets that are not sensitive to the
weather or economic downturn. The advancement of such technologies appears
beneficial as business entities strive to comply with provisions of the Federal
Clean Air Act, legislation which applies strict anti-pollution standards to
factories, fleet and mass transit vehicles, and electric power plants. The law
is likely to increase demand for natural gas, but the extent thereof will depend
on how the Act is implemented and enforced. Gas demand could also increase as
the result of the Energy Policy Act of 1992 which requires and encourages large
vehicle fleets to operate on alternative fuels such as natural gas. The Energy
Policy Act also created a new class of independent power producers exempt from
utility regulation, which could lead to the construction of additional gas-
fueled generating facilities.
 
The Company is also pursuing other technological opportunities, including gas
cooling equipment, fuel cell power generation, coal drying processes and the
promotion of natural gas powered vehicles (NGVs). Fleet operators and mass
transit authorities are using NGVs for both fuel cost efficiencies and to reduce
environmental pollution. Despite the environmental benefits of NGVs, it appears
unlikely that such vehicles will replace a significant number of gasoline
powered vehicles in the near future, given the lack of a nationwide network of
refueling facilities and the current cost of retrofitting vehicles. However,
beginning in 1997, the Federal Clean Air Act could require 22 of the country's
most polluted regions to convert a portion of their fleet vehicles to natural
gas. The Company supplies natural gas to utilities that serve Baltimore,
Washington, D.C., and New York, three metropolitan areas directly affected by
this provision of the Act.
 
RATE MATTERS (See Note 2 to the consolidated financial statements, page 49.)
 
The regulated subsidiaries continue to seek general rate increases on a timely
basis to recover increased operating costs and to ensure that rates of return
are compatible with the cost of raising capital. In addition to general rate
increases, subsidiary companies make separate filings with their respective
regulatory commissions to reflect changes in the costs of purchased gas.
 
The following is a summary of rate activity during 1995 and to date.
 
       CNG TRANSMISSION
 
CNG Transmission received FERC approval to implement Order 636 effective October
1, 1993, in accordance with the terms of a comprehensive stipulation and
agreement reached with customers and others. With FERC approval, CNG
Transmission direct billed and began collecting transition costs amounting to
$177.9 million and $9.8 million in December 1993 and August 1994, respectively.
During 1995, CNG Transmission made refunds to its customers and affiliates of
$9.1 million in connection with the prior direct billings.
 
On November 29, 1995, the FERC approved a settlement agreement filed by CNG
Transmission in connection with its December 30, 1993 general rate filing. The
settlement resolves the outstanding issues in the case and results in an annual
revenue increase of $40 million, retroactive to July 1, 1994, the date new rates
went into effect subject to refund. The settlement reflects an imputed return on
equity of 11.30 percent. Customer refunds resulting from the settlement totaling
$81.5 million were made in
 
                                       14
<PAGE>   17
 
ITEM 1.     BUSINESS (Continued)
 
December 1995 with an additional $4.8 million expected to be refunded in the
first quarter of 1996. In its filing, CNG Transmission had requested a $106.6
million increase in annual revenues and a return on equity of 14.00 percent.
 
       DISTRIBUTION SUBSIDIARIES
 
On August 3, 1995, the Pennsylvania Public Utility Commission approved a
settlement agreement filed by Peoples Natural Gas covering its February 1, 1995
general rate filing. The approved settlement includes an $8.0 million annual
revenue increase with new rates effective August 4, 1995. In its filing, Peoples
Natural Gas had originally requested a $32.8 million increase in annual
revenues.
 
On September 1, 1995, Virginia Natural Gas submitted an expedited rate filing
with the Virginia State Corporation Commission (VSCC) requesting an annual
revenue increase of $7.2 million. The new rates went into effect, subject to
refund, on October 1, 1995. On February 23, 1996, Virginia Natural Gas requested
approval from the VSCC to withdraw this rate filing. Pending VSCC approval,
customer refunds related to the filing will be made later in 1996.
 
On October 26, 1995, the Public Service Commission of West Virginia approved a
settlement agreement filed by Hope Gas in connection with its January 4, 1995
general rate filing. The new rates became effective November 1, 1995. The
approved settlement agreement increased base rates but eliminated the purchased
gas cost adjustment mechanism for the three-year period covered by the
settlement. Therefore, any increase or decrease in gas costs over the base
amount included in rates will not be passed on to customers during the
settlement period.
 
On November 8, 1995, a $6.2 million annual revenue increase became effective at
East Ohio Gas in connection with the November 3, 1994 settlement of its general
rate case, as approved by the Public Utilities Commission of Ohio. This increase
is in addition to the $62.4 million annual revenue increase that became
effective November 8, 1994.
 
On January 30, 1996, the VSCC issued a final order in connection with Virginia
Natural Gas' September 1, 1994 general rate filing. The order results in an
annual revenue increase of $6.1 million, retroactive to October 1, 1994, the
date new rates went into effect subject to refund. Customer refunds resulting
from the order will be made in the first half of 1996. The order reflects an
imputed return on equity of 11.3 percent. In its filing, Virginia Natural Gas
had requested a $9.9 million increase in annual revenues and a return on equity
of 11.75 percent.
 
                                       15
<PAGE>   18
 
ITEM 1.     BUSINESS (Concluded)
 
EXECUTIVE OFFICERS OF THE COMPANY (Note 1)
 
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------
        Name, Age and                                 Business Experience
      Position (Note 2)                             During Past Five Years
---------------------------------------------------------------------------------------------
<S>                               <C>
George A. Davidson, Jr. (57)      Mr. Davidson was elected to his present position on May 19,
Chairman of the Board and         1987, and has been a Director since October 1985.
Chief Executive Officer,
and Director

Robert W. Best (49)               Mr. Best joined the Company and was elected to his present
Senior Vice President             position on January 1, 1996. Prior to joining the Company,
                                  Mr. Best was Senior Vice President, Natural Gas of Transco
                                  Energy from February 1992 to May 1995 and President and
                                  Chief Operating Officer of Texas Gas (a wholly owned
                                  subsidiary of Transco Energy) from April 1989 to May 1995.

William F. Fritsche, Jr. (64)     Mr. Fritsche was elected to his present position on May 1,
Senior Vice President,            1995. He served as President of East Ohio Gas from
Distribution                      September 1994 to April 1995. From June 1987 to September
                                  1994, he served as President of Virginia Natural Gas.

David M. Westfall (48)            Mr. Westfall was elected to his present position on
Senior Vice President and         December 1, 1995. He served as Senior Vice President,
Chief Financial Officer           Financial from January 1995 to November 1995. From January
                                  1988 to January 1995, he served as Senior Vice President at
                                  CNG Transmission.

Stephen E. Williams (47)          Mr. Williams was elected to his present position on January
Senior Vice President and         1, 1993. He served as Associate General Counsel from
General Counsel                   September 1992 to January 1993. From April 1987 to
                                  September 1992, he served as General Counsel and Secretary
                                  of CNG Transmission.

Stephen R. McGreevy (45)          Mr. McGreevy was elected to his present position on March
Vice President, Accounting        1, 1993. He served as Controller from January 1986 to March
and Financial Control             1993.

Laura J. McKeown (37)             Ms. McKeown was elected to her present position on May 16,
Secretary                         1989.

Robert M. Sable, Jr. (44)         Mr. Sable was elected to his present position on May 1,
Treasurer                         1995. He served as Senior Assistant Treasurer from January
                                  1993 to April 1995 and Assistant Treasurer from May 1987 to
                                  January 1993.

Thomas F. Garbe (43)              Mr. Garbe was elected to his present position on March 1,
Controller                        1993. He served as Senior Assistant Controller from May
                                  1991 to March 1993 and as Assistant Controller from January
                                  1986 to May 1991.
---------------------------------------------------------------------------------------------
<FN>
 
Notes:
(1) The Company has been advised that there are no family relationships between
    any of the officers listed, and there is no arrangement or understanding
    between any of them and any other person pursuant to which the individual
    was elected as an officer.
 
(2) The By-Laws of the Company provide that each officer shall hold office until
    a successor is chosen and qualified.
</TABLE>
 
                                       16
<PAGE>   19
 
ITEM 2.     PROPERTIES
 
GENERAL INFORMATION ON FACILITIES (Maps are on pages 18 and 19.)
 
The Company's total gross investment in property, plant and equipment was $7.9
billion at December 31, 1995. The largest portion of this investment (61%) is in
facilities located in the Appalachian area. Another significant portion (24%) is
located in the Gulf of Mexico.
 
Of the $7.9 billion investment, $3.5 billion is in production and gathering
systems, of which 59 percent is invested in the Gulf of Mexico and the Gulf
coast and 26 percent in the Appalachian area. The Company's production
subsidiary, CNG Producing, accounts for $2.9 billion of the $3.5 billion
investment, and CNG Transmission and the distribution subsidiaries account for
the remaining $600 million. In addition to the wells and acreage listed
elsewhere in ITEM 2, this investment includes 7,010 miles of gathering lines
which are located almost entirely within the Appalachian area.
 
The Company's investment in its gas distribution network includes 29,043 miles
of pipe, exclusive of service pipe, the cost of which represents 61% of the $1.7
billion invested in the total function.
 
The Company's storage operation, the largest in the industry, consists of 26
storage fields, 332,288 acres of operated leaseholds, 2,060 storage wells and
821 miles of pipe. The investment in storage properties is $685 million,
including $115 million of cushion gas stored.
 
Of the $1.5 billion invested in transmission facilities, 68% represents the cost
of 7,317 miles of pipe required to move large volumes of gas throughout the
Company's operating area.
 
The Company has 105 compressor stations with 485,018 installed compressor
horsepower. Some of the stations are used interchangeably for several functions.
 
The Company's investment in its natural gas system is considered suitable to do
all things necessary to bring gas to the consumer. The Company's properties
provided the capacity to meet a record system peak day sendout, including
transportation service, of 11.4 Bcf on February 6, 1995.
 
                                       17
<PAGE>   20
 

Map of Principal Facilities at December 31, 1995
(GRAPHIC MATERIAL OMITTED)









                                       18
<PAGE>   21


Map of Exploration and Production Areas at December 31, 1995
(GRAPHIC MATERIAL OMITTED)









                                       19
<PAGE>   22
 
ITEM 2.     PROPERTIES (Continued)
 
GAS AND OIL PRODUCING ACTIVITIES (See Note 19(A) to the consolidated financial
statements, page 68.)
 
Properties and activities subject to cost-of-service rate regulation are shown
together with non-cost-of-service properties (those subject to contractual
arrangements, and Canadian properties) and activities in the statistical
presentations which follow.
 
       COMPANY-OWNED RESERVES
 
Estimated net quantities of proved gas and oil reserves at December 31, 1993
through 1995, follow:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------
December 31,                            1995                   1994                   1993
--------------------------------------------------------------------------------------------------
                                   Proved      Total      Proved      Total      Proved      Total
                                 Developed    Proved    Developed    Proved    Developed    Proved
--------------------------------------------------------------------------------------------------
<S>                              <C>        <C>         <C>          <C>       <C>          <C>
Gas Reserves (Bcf)
     Non-cost-of-service......        717       985          730        901         761        885
     Cost-of-service..........         56        56           71         71          75         75
                                   ------    ------       ------     ------      ------     ------
          Total...............        773     1,041          801        972         836        960
                                   ======    ======       ======     ======      ======     ======
Oil Reserves (000 Bbls)
     Non-cost-of-service......     19,838    45,791       20,379     46,255      21,936     27,596
     Cost-of-service..........         --        --          256        256         287        287
                                   ------    ------       ------     ------      ------     ------
          Total...............     19,838    45,791       20,635     46,511      22,223     27,883
                                   ======    ======       ======     ======      ======     ======
--------------------------------------------------------------------------------------------------
</TABLE>
 
CNG Producing, East Ohio Gas, Hope Gas, Peoples Natural Gas and CNG Transmission
file Form EIA-23 with the Department of Energy. The reserves reported at
December 31, 1994, as well as those which will be reported at December 31, 1995,
are not reconcilable with Company-owned reserves because they are calculated on
an operated basis and include working interest reserves of all parties. East
Ohio Gas sold all of its remaining gas and oil reserves (which are classified as
cost-of-service in the table above) during 1995.
 
       QUANTITIES OF GAS AND OIL PRODUCED
 
Net quantities (net before royalty) of gas and oil produced during each of the
last three years follow:
 
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
Years Ended December 31,                                              1995      1994      1993
----------------------------------------------------------------------------------------------
<S>                                                                  <C>       <C>       <C>
Gas Production (Bcf)
     Non-cost-of-service.........................................      103       114       124
     Cost-of-service.............................................        4         6         6
                                                                     -----     -----     -----
          Total..................................................      107       120       130
                                                                     =====     =====     =====
Oil Production (000 Bbls)
     Non-cost-of-service.........................................    3,132     3,333     3,907
     Cost-of-service.............................................       17        24        29
                                                                     -----     -----     -----
          Total..................................................    3,149     3,357     3,936
                                                                     =====     =====     =====
----------------------------------------------------------------------------------------------
</TABLE>
 
The average sales price (including transfers to other operations as determined
under Financial Accounting Standards Board rules) per Mcf of non-cost-of-service
gas produced during the calendar years 1993 through 1995 was $2.24, $2.16 and
$1.89, respectively. The respective average sales prices for oil were $15.66,
$14.45 and $16.04 per barrel. The average production (lifting) cost per Mcf
 
                                       20
<PAGE>   23
 
ITEM 2.     PROPERTIES (Continued)
 
equivalent of non-cost-of-service gas and oil produced during the years 1993
through 1995 was $.33, $.32 and $.34, respectively.
 
       PRODUCTIVE WELLS
 
The number of productive gas and oil wells in which the subsidiary companies
have an interest at December 31, 1995, follow:
 
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------
                                                               Gas Wells          Oil Wells
                                                            ---------------     -------------
                                                            Gross      Net      Gross     Net
---------------------------------------------------------------------------------------------
<S>                                                         <C>       <C>       <C>       <C>
Non-cost-of-service*....................................    5,145     4,408      859      380
Cost-of-service.........................................    1,635     1,320       --       --
                                                            -----     -----      ---      ---
     Total..............................................    6,780     5,728      859      380
                                                            =====     =====      ===      ===
---------------------------------------------------------------------------------------------
<FN>
 
* Includes 81 gross (28 net) multiple completion gas wells and 6 gross (3 net)
  multiple completion oil wells.
</TABLE>
 
       ACREAGE
 
The following table sets forth the gross and net developed and undeveloped
acreage of the subsidiary companies at December 31, 1995:
 
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
                                              Developed Acreage           Undeveloped Acreage
                                           -----------------------       ---------------------
                                             Gross          Net           Gross          Net
----------------------------------------------------------------------------------------------
<S>                                        <C>           <C>             <C>           <C>
Non-cost-of-service....................    1,631,188     1,239,603       894,837       582,830
Cost-of-service........................      215,422       212,966        13,391         9,882
                                           ---------     ---------       -------       -------
Total..................................    1,846,610     1,452,569       908,228       592,712
                                           =========     =========       =======       =======
----------------------------------------------------------------------------------------------
</TABLE>
 
Approximately 30% of the foregoing non-cost-of-service undeveloped net acreage
and 100% of the cost-of-service undeveloped net acreage is located in the
Appalachian area.
 
       NET WELLS DRILLED IN THE CALENDAR YEAR
 
The number of non-cost-of-service net wells completed during each of the last
three years follow (there were no cost-of-service wells completed during this
three-year period):
 
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
                                     Exploratory             Development               Total
                                  ------------------     -------------------     ------------------
                                  Productive     Dry     Productive*     Dry     Productive     Dry
---------------------------------------------------------------------------------------------------
<S>                                   <C>       <C>          <C>         <C>        <C>        <C>
Years Ended December 31,
     1995......................        4          9           12          1          16         10
     1994......................        2         10           22          1          24         11
     1993......................        2          6           13          1          15          7
---------------------------------------------------------------------------------------------------
<FN>
 
* Includes Canadian completions: 1995 - 3 wells, 1994 - 1 well and 1993 - 1
  well.
</TABLE>
 
As of December 31, 1995, 13 gross (6 net) non-cost-of-service wells were in
process of drilling, including wells temporarily suspended. As of December 31,
1995, the Company was engaged in waterflood projects in Oklahoma and Texas, a
gas injection program in the Gulf of Mexico, and an enhanced oil recovery
program in Alberta, Canada.
 
                                       21
<PAGE>   24
 
ITEM 2.     PROPERTIES (Concluded)
 
       GAS PURCHASE CONTRACT RESERVES (AT DECEMBER 31, 1995) AND AVAILABILITY OF
       SUPPLY (CALENDAR YEAR 1996)
 
Gas purchase reserves under contract with independent producers in the
Appalachian area total 573 Bcf at December 31, 1995. In addition, at December
31, 1995, the Company had gas supply contracts with various other producers and
marketers with contract lengths ranging from a few months to nine years. The
volume of gas available to the Company under these supply contracts totals 289
Bcf if all volumes are requested. These gas purchase contract reserve and gas
supply contract volume amounts are as contained in the February 12, 1996 report
of Ralph E. Davis Associates, Inc. Of the total 573 Bcf under contract from
Appalachian producers, the volume of gas expected to be purchased in 1996 under
such contracts is not estimable as such contracts are generally life-of-the-well
arrangements and contain provisions adaptable to changing market conditions. Of
the total 289 Bcf available under contract from other producers and marketers,
approximately 178 Bcf of gas will be available to the Company in 1996, assuming
all volumes are requested.
 
The Company anticipates that substantial volumes of gas will be available for
purchase during 1996 on the spot market. Due to the nature of spot market
transactions, the volumes of such gas available to the Company in 1996 cannot be
reasonably estimated. However, for the calendar year 1996, the Company expects
its distribution subsidiaries to have approximately 361 Bcf of firm transport
capacity available on upstream pipelines and 122 Bcf of storage capacity
available to meet their customer requirements.
 
The volumes expected to be available from Company-owned wells in 1996 amount to
129 Bcf of gas and 3,647 thousand barrels of oil. Included in these amounts are
125 Bcf of gas and 3,647 thousand barrels of oil expected to be available from
the Company's non-cost-of-service properties. The foregoing volumes are based on
the Company's current production estimates of proved gas and oil reserves.
Actual production may differ from these amounts due to a number of factors,
including changing market conditions and the acquisition or sale of reserves.
 
ITEM 3.     LEGAL PROCEEDINGS
 
Reference is made to Note 16 to the consolidated financial statements, page 63,
for environmental-related information.
 
Reference is made to "Rate Matters," page 14, for descriptions of certain
regulatory proceedings.
 
ITEM 4.     SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
 
Not applicable
 
                                    PART II
                                    -------

ITEM 5.     MARKET FOR THE COMPANY'S COMMON STOCK AND RELATED
            STOCKHOLDER MATTERS
 
This information is included in Note 19(C) to the consolidated financial
statements, page 73, and reference is made thereto.
 
                                       22
<PAGE>   25
 
ITEM 6.     SELECTED FINANCIAL DATA
 
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------
SUMMARY OF FINANCIAL DATA (Thousand $)        1995*           1994          1993          1992          1991
------------------------------------------------------------------------------------------------------------
<S>                                     <C>            <C>           <C>           <C>           <C>
EARNINGS
Gas sales............................   $2,595,103     $ 2,402,861   $ 2,615,036   $ 1,951,545   $ 2,082,927
Gas transportation, storage and
  other..............................      712,222         633,167       569,049       569,305       524,079
    Total operating revenues.........    3,307,325       3,036,028     3,184,085     2,520,850     2,607,006
Purchased gas........................    1,590,137       1,424,020     1,594,373       990,604     1,157,096
Transport capacity and other
  purchased products.................      153,577         107,094        79,001        73,001        80,131
Operation and maintenance............      739,612**       689,575       677,666       657,825       639,530
Depreciation and amortization........      256,636         279,317       294,648       287,840       284,712
Impairment of gas and oil producing
  properties.........................      226,209              --            --            --            --
Taxes, other than income taxes.......      191,698         192,617       181,053       169,315       160,632
    Operating income before income
      taxes..........................      149,456         343,405       357,344       342,265       284,905
Income taxes.........................        2,943          82,427        99,906        68,623        54,844
Other income-net.....................       10,760           9,694        10,531         4,749        26,381
Write-down of coal properties........       31,266              --            --            --            --
Interest charges.....................      104,663          87,501        79,475        83,433        87,829
Income before change in
  accounting principle...............       21,344         183,171       188,494       194,958       168,613
Cumulative effect of applying SFAS
  No. 109............................           --              --        17,422            --            --
    Net income.......................       21,344         183,171       205,916       194,958       168,613
Per share of common stock
    Income before change in
      accounting principle...........         $.23           $1.97         $2.03         $2.19         $1.94
    Cumulative effect of applying
      SFAS No. 109...................           --              --           .19            --            --
    Net income.......................         $.23           $1.97         $2.22         $2.19         $1.94
Average common shares outstanding....   93,246,114      92,999,693    92,808,156    89,127,805    86,836,920
Return on average stockholders'
  equity.............................         1.0%            8.4%          9.6%          9.7%          9.0%
Times fixed charges earned...........         1.21            3.53          3.95          3.41          2.86
------------------------------------------------------------------------------------------------------------
DIVIDENDS--CASH
Paid per common share................        $1.94           $1.94         $1.92         $1.90         $1.88
    Payout ratio.....................       843.5%           98.5%         86.5%         86.8%         96.9%
Declared per common share............        $1.94           $1.94        $1.925        $1.905        $1.885
------------------------------------------------------------------------------------------------------------
ASSETS
Total assets.........................   $5,418,293     $ 5,518,673   $ 5,437,188   $ 5,158,871   $ 5,026,775
Property, plant and equipment
    Total investment.................    7,929,350       7,676,956     7,346,028     7,087,102     6,749,165
    Accumulated depreciation.........    4,016,945       3,650,310     3,429,760     3,212,202     3,010,776
Capital expenditures and
  acquisitions.......................      439,393         437,785       342,569       441,518       493,033
------------------------------------------------------------------------------------------------------------
CAPITAL STRUCTURE
Total common stockholders' equity....   $2,045,818     $ 2,184,334   $ 2,176,432   $ 2,132,838   $ 1,889,783
Long-term debt.......................    1,291,811       1,151,973     1,158,648     1,111,956     1,159,123
                                        ----------     -----------   -----------   -----------   -----------
    Total capitalization.............   $3,337,629     $ 3,336,307   $ 3,335,080   $ 3,244,794   $ 3,048,906
                                        ==========     ===========   ===========   ===========   ===========
Long-term debt ratio.................        38.7%           34.5%         34.7%         34.3%         38.0%
Shares of common stock outstanding
  at year-end........................   93,591,623      93,027,847    92,933,828    92,557,017    87,321,917
Common stockholders' equity
  per share..........................       $21.86          $23.48        $23.42        $23.04        $21.64
------------------------------------------------------------------------------------------------------------
<FN>
 
 * Certain amounts and ratios are not comparable with prior years due to special
   charges.
** Includes special charges for workforce reduction costs of $42,555,000.
</TABLE>
 
                                       23
<PAGE>   26
 
ITEM 7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
            RESULTS OF OPERATIONS
 
RESULTS OF OPERATIONS
 
NET INCOME
 
Net income in 1995 was $21.3 million, or $.23 a share, compared with net income
of $183.2 million, or $1.97 a share, in 1994. Net income in 1993 was $205.9
million, or $2.22 a share.
 
Earnings for 1995 included the effects of three special charges. During the
first quarter, the Company recorded a non-cash charge to write down the cost of
gas and oil producing properties, amounting to $145.0 million after taxes, or
$1.56 a share. In the second quarter, the Company recognized a non-cash charge
of $20.3 million after taxes, or $.22 a share, in connection with a write-down
of coal properties. In addition, during the year the Company recorded charges
totaling $25.6 million after taxes, or $.27 a share, for costs related to
workforce reduction programs. Excluding these special items, net income for 1995
would have been $212.3 million, or $2.28 a share. Reference is made to Notes 3
and 4 to the consolidated financial statements, pages 49 and 50, for details of
the special charges recognized in 1995.
 
The favorable effects of new rates in place for most of the Company's gas
distribution and transmission customers, colder weather than in 1994 and lower
aggregate wage and benefit costs in the latter part of the year resulting from
the workforce reduction programs more than offset the impact of continued low
wellhead prices for natural gas and lower gas and oil production in 1995.
Weather in the Company's retail service territories was 2.2 percent colder than
in 1994 but 1.1 percent warmer than normal. Weather in 1995 was warmer than
normal for the sixth consecutive year. Normal weather represents a measure of
temperature experienced over a 30-year period.
 
Warmer weather, higher operating costs, lower average wellhead gas prices,
reduced gas production and higher interest expense contributed to the earnings
decline in 1994 compared with 1993. Normal weather would have added about $.12 a
share to the $1.97 a share reported for 1994.
 
In 1993, higher prices for natural gas production and increased gas deliveries
resulting from pipeline expansion projects, which more than offset warmer than
normal weather, were major factors in the year's results. Normal weather in the
Company's retail service areas in 1993 would have added about $.06 a share to
the $2.22 a share reported. Also, the recognition of deferred tax benefits of
$17.4 million, or $.19 a share, resulting from the mandatory adoption of
Statement of Financial Accounting Standards (SFAS) No. 109 and reported as a
separate component of net income as the cumulative effect of the accounting
change, favorably impacted 1993 earnings. The effect, however, was partially
offset by higher income taxes due to the increase in the federal corporate
income tax rate from 34 percent to 35 percent enacted in August 1993. The
effects of this rate change included an $11.4 million, or $.12 a share,
adjustment to previously recorded deferred tax balances and a $2.7 million, or
$.03 a share, increase in current taxes to reflect the new tax law retroactive
to January 1, 1993.
 
OPERATING REVENUES
 
Operating revenues include revenues from gas and oil sales, transportation of
gas, storage service, brokering activities, by-product operations and, beginning
in 1995, wholesale electric sales.
 
Total operating revenues in 1995 were $3,307.3 million, an increase of $271.3
million compared to 1994 operating revenues of $3,036.0 million. Regulated gas
sales revenues in 1995 decreased $81.9 million from 1994, to $1,597.4 million,
with sales volumes increasing 4.9 billion cubic feet (Bcf) to 289.9 Bcf. Colder
weather compared with 1994 led to the increase in sales volumes while lower unit
purchased gas costs reflected in revenues was responsible for the decline in
sales revenue. Nonregulated gas sales revenues increased $274.1 million in 1995,
with sales volumes increasing 223.8 Bcf over the 1994 period to 556.6 Bcf. These
increases were attributable to the growth of the Company's energy marketing
 
                                       24
<PAGE>   27
 
ITEM 7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
            RESULTS OF OPERATIONS (Continued)
 
services component. The increased volumes sold more than offset the effects of
lower wellhead prices and production at the exploration and production
operations. Gas transportation and storage revenues were $456.4 million in 1995,
up $46.8 million over 1994. The increase was due principally to higher
transportation revenues, which increased $39.5 million due to both increased
volumes and rates. Other operating revenues increased $32.3 million in 1995 to
$255.8 million. The increase reflects wholesale sales of electricity of $21.8
million in 1995 by the energy marketing services component.
 
Total operating revenues in 1994 declined $148.1 million compared to 1993
operating revenues of $3,184.1 million. Regulated gas sales revenues were down
$393.9 million in 1994 primarily due to the abandonment by CNG Transmission
Corporation (CNG Transmission) of its traditional sales service with the
implementation of Federal Energy Regulatory Commission (FERC) Order 636 in
October 1993. Retail sales revenues were higher in 1994 as higher average sales
prices received from all customer classes more than offset a decline in gas
volumes sold resulting from the warmer weather in 1994. Nonregulated gas sales
revenues increased $181.8 million, representing a significant increase in
volumes sold due to a full year of operation at CNG Energy Services Corporation
(CNG Energy Services) partially offset by a decline in the average sales price.
Revenues from gas transportation and storage services rose $76.3 million
reflecting CNG Transmission's first full year of operations under FERC Order
636. Other operating revenues declined $12.3 million, primarily due to lower oil
sales volumes and prices.
 
OPERATING EXPENSES
 
Operating expenses, including taxes, increased 14 percent in 1995 to $3,160.8
million. Excluding the impact of the impairment of gas and oil producing
properties and the workforce reduction charges, operating expenses for 1995
would have been $2,990.2 million, up $215.1 million. Operating expenses in 1994
were $2,775.1 million, down 5 percent from $2,926.6 million in 1993.
 
Purchased gas consistently represents the largest operating expense item for the
Company. Purchased gas costs were $1,590.1 million in 1995, $1,424.0 million in
1994 and $1,594.4 million in 1993. This expense is influenced primarily by
changes in gas sales requirements, the price and mix of gas supplies, and the
timing of recoveries of deferred purchased gas costs. Total purchased gas
expense was higher in 1995 due primarily to increased volume requirements
associated with nonregulated gas sales. This factor more than offset lower unit
purchased gas costs, which reflected the nationwide decline in gas prices. Lower
spot market gas prices and lower recoveries of previously deferred gas costs by
the distribution subsidiaries, partially offset by increased volume
requirements, were the primary factors for the decline in 1994.
 
Transport capacity and other purchased products expense includes the cost of
pipeline capacity not associated with gas purchased and the cost of liquids,
by-products and, beginning in 1995, electricity purchased for resale. This
expense increased $46.5 million and $28.1 million in 1995 and 1994,
respectively, primarily due to increased transport capacity purchased from other
pipeline companies in both years, and electricity purchased for resale in 1995
totaling $19.6 million.
 
Excluding the $42.6 million of workforce reduction charges, combined operation
and maintenance expense increased $7.5 million in 1995. Higher customer-related
expenses, slightly higher overhead costs and the regulator-mandated adjustment
for certain previously deferred costs in connection with the settlement of CNG
Transmission's rate case were factors contributing to the $10.8 million increase
in operation expense. Lower royalties paid as a result of both lower gas
wellhead prices and production and the benefits of the workforce reduction
programs in the latter part of 1995 helped to minimize the increase. Maintenance
expense declined $3.3 million, to $85.9 million, in 1995.
 
Combined operation and maintenance expense increased $11.9 million in 1994, to
$689.6 million. The increase in operation expense of $9.9 million, to $600.4
million, was due principally to higher payroll
 
                                       25
<PAGE>   28
 
ITEM 7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
            RESULTS OF OPERATIONS (Continued)
 
costs, including weather-related overtime during the unusually cold weather
early in 1994, and overhead costs. Maintenance expense was up $2.0 million, or 2
percent, to $89.2 million.
 
Total depreciation and amortization charges were down $22.7 million in 1995 and
$15.3 million in 1994 due to lower amortization charges for the Company's
exploration and production operations. Amortization of gas and oil producing
properties declined in 1995 primarily as the result of the lower investment
following the impairment of these properties in the first quarter. Reserve
additions and lower production also contributed to the lower charges in 1995,
and were the primary reasons for lower amortization charges in 1994.
Depreciation expense for the regulated subsidiaries was higher in both 1995 and
1994 due principally to the increased level of plant investment.
 
Taxes, other than income taxes, decreased $.9 million in 1995 due chiefly to
lower revenue-based taxes and increased $11.5 million in 1994 due in large part
to higher property taxes.
 
Income taxes decreased $79.4 million in 1995 compared to 1994 due mainly to
lower pretax earnings. Income taxes declined $17.5 million in 1994 compared to
the prior year primarily as a result of lower pretax earnings and an $11.4
million adjustment recorded in 1993 to deferred income tax expense due to the
increase in the federal corporate income tax rate. Reference is made to Note 7
to the consolidated financial statements for information on the effects of the
1993 increase in the federal corporate income tax rate.
 
OTHER INCOME
 
Excluding the write-down of coal properties of $31.3 million, 1995 other income
would have been $10.8 million, compared to $9.7 million in 1994 and $10.5
million in 1993. Interest revenues increased $4.1 million in 1995 due primarily
to the higher level of temporary cash investments during the year. Interest
revenues were $1.7 million higher in 1994, reflecting CNG Transmission's billing
of Order 636 transition costs in December 1993 and August 1994. Interest
revenues were up $1.5 million in 1993 due primarily to the recognition of
interest in connection with certain regulatory programs. The changes in
"Other-net" in the Consolidated Statement of Income reflect primarily the
differing levels of income recognized from the Company's external investments
and, in 1995, losses related to minor property dispositions at certain regulated
subsidiaries.
 
INTEREST CHARGES
 
Interest on long-term debt was up $7.0 million in 1995 due chiefly to interest
expense related to the $150 million of debentures issued in April 1995. Interest
on long-term debt increased $3.5 million in 1994, reflecting both a full year of
interest expense on debentures issued in 1993 and lower interest charges due to
redemptions and repayments of debenture borrowings in 1993. During 1993, the
Company called $266.2 million of its higher-cost borrowings, while issuing
$300.0 million of lower rate debentures. Other interest expense increased in
1995 as a result of higher interest rates on commercial paper borrowings. Other
interest expense increased in 1994 primarily due to higher interest on refund
obligations to customers. The amount of interest expense capitalized in 1995
declined from the level of the past two years due to the lower investment in
unproved properties held by the exploration and production operations.
 
FOURTH QUARTER RESULTS
 
The Company's net income for the fourth quarter of 1995 was $87.4 million
compared with $73.8 million earned in the 1994 fourth quarter, an increase of
$13.6 million. On a per share basis, the 1995 quarter was $.94 compared with
$.79 in 1994. The weather in the Company's retail service areas was 35 percent
colder than in the 1994 fourth quarter, while the Company's average gas wellhead
prices were up $.29
 
                                       26
<PAGE>   29
 
ITEM 7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
            RESULTS OF OPERATIONS (Continued)
 
per thousand cubic feet (Mcf) compared with the 1994 fourth quarter. Proceeds
from the settlement of a major pipeline bankruptcy case and the effects of the
workforce reduction programs also contributed favorably to fourth quarter
results. These positive factors were partially offset by low gas margins, the
recognition of mark-to-market losses for storage-related futures contracts at
the energy marketing services component and the timing of certain discretionary
overhead expenses.
 
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------
QUARTERS ENDED DECEMBER 31,                                                1995         1994
---------------------------------------------------------------------------------------------
                                                                            (In Millions)
<S>                                                                      <C>          <C>
Operating revenues..................................................     $ 935.5      $ 788.6
Operating expenses..................................................      (775.0)      (666.8)
Operating income before income taxes................................       160.5        121.8
Income taxes........................................................       (44.6)       (27.3)
Other income/expenses-net...........................................       (28.5)       (20.7)
                                                                         -------      -------
Net income..........................................................     $  87.4      $  73.8
                                                                         =======      =======
Per common share (in dollars).......................................        $.94         $.79
Average shares outstanding (thousands)..............................      93,442       93,026
---------------------------------------------------------------------------------------------
</TABLE>
 
NEW ACCOUNTING STANDARDS
 
In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of." This standard is effective for fiscal years beginning
after December 15, 1995, and the Company will adopt the standard effective
January 1, 1996. The adoption is not expected to have a material effect on the
Company's financial position, results of operations or cash flows. Reference is
made to Note 1 to the consolidated financial statements, page 47, regarding this
new standard.
 
In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based
Compensation." Although the Company does not anticipate changing its accounting
method for stock-based compensation as a result of this new standard, the
disclosure requirements of SFAS No. 123 are effective for financial statements
for fiscal years beginning after December 15, 1995. Reference is made to Note 1
to the consolidated financial statements, page 48, regarding SFAS No. 123.
 
COMPONENTS OF THE BUSINESS
 
Due to the regulated nature of the distribution and transmission components of
the Company's business, operating results can be affected by regulatory delays
when price increases are sought through general rate filings to recover certain
higher costs of operations. Weather is also an important factor since a major
portion of the gas sold or transported by the distribution and transmission
operations is ultimately used for space heating.
 
The following presents the operating results for each of the Company's business
components. Reference is made to Note 18 to the consolidated financial
statements, page 65, for additional disaggregated information pertaining to the
Company's operations.
 
                                       27
<PAGE>   30
 
ITEM 7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
            RESULTS OF OPERATIONS (Continued)
 
OPERATING INCOME BEFORE INCOME TAXES
 
Operating income before income taxes for the Company's business components for
the last three years is shown in the table below.
 
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
OPERATING INCOME BEFORE INCOME TAXES                              1995*       1994        1993
----------------------------------------------------------------------------------------------
                                                                        (In Millions)
<S>                                                            <C>          <C>         <C>
Distribution..............................................     $ 207.5      $159.0      $166.9
Transmission..............................................       150.4       146.3       143.4
Exploration and production................................      (200.5)       34.0        47.3
Energy marketing services.................................        (5.7)         --          --
Other**...................................................         2.9         7.6         5.7
Corporate and eliminations................................        (5.1)       (3.5)       (6.0)
                                                               -------      ------      ------
     Total................................................     $ 149.5      $343.4      $357.3
                                                               =======      ======      ======
----------------------------------------------------------------------------------------------
<FN>
 
 * Amount for the exploration and production operations includes the impact of
   the write-down of gas and oil producing properties amounting to $226.2
   million. Amounts for the distribution, transmission, exploration and
   production, energy marketing services and corporate components include the
   effect of workforce reduction charges totaling $22.3 million, $6.0 million,
   $7.7 million, $.5 million and $4.6 million, respectively.
** Includes Consolidated LNG, CNG Research and CNG Coal. CNG Energy Services and
   CNG Power (formerly CNG Energy) are included in the 1993 and 1994 amounts.
   CNG Power Services is also included in the 1994 amount.
</TABLE>
 
DISTRIBUTION
 
"Distribution" represents the results of the five retail gas distribution
subsidiaries, including their minor gas and oil production activities.
 
Sales growth in the Company's residential service areas in Ohio, Pennsylvania
and West Virginia has generally been limited since such areas have experienced
minimal population growth, and the vast majority of households in these areas
already use natural gas for space heating. Opportunity for growth in the retail
sales market is expected to continue at Virginia Natural Gas, Inc. (Virginia
Natural Gas), due to customer conversions from other energy sources and the past
and potential future expansion of its service territory. Since the Company's
acquisition of this subsidiary in 1990, it has experienced an annual customer
growth rate of about 4 percent, well above the 1 percent rate for the other
distribution subsidiaries.
 
       OPERATING INCOME BEFORE INCOME TAXES
 
Operating income before income taxes for the gas distribution operations was
$207.5 million in 1995, up $48.5 million from 1994. Excluding workforce
reduction charges amounting to $22.3 million, operating income for 1995 would
have been $229.8 million. In addition to the general rate increases placed into
effect in late 1994 and in 1995 at four of the distribution subsidiaries (see
"State Regulatory Issues"), colder weather, the addition of new customers,
higher transport volumes and lower wage and benefit costs in the latter part of
the year due to the workforce reduction programs contributed favorably to 1995
results. Overall, weather in the Company's retail service territories was 2
percent colder than 1994, but was 1 percent warmer than normal.
 
Operating income before income taxes for the gas distribution operations
declined $7.9 million in 1994, to $159.0 million. Warmer weather and higher
costs of operations were the principal reasons for the decline. Overall, weather
in the Company's retail service area was 3 percent warmer than 1993 and 4
percent warmer than normal. The higher operating costs were addressed in rate
filings made by the subsidiaries during the year. Two subsidiaries were granted
rate increases and another began collecting higher rates,
 
                                       28
<PAGE>   31
 
ITEM 7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
            RESULTS OF OPERATIONS (Continued)
 
subject to refund. However, the increases were placed into effect in the latter
part of the year and did not have a significant impact on 1994 results.
 
The net addition of about 17,800 residential and commercial gas sales customers,
a minor increase in throughput, and the full year impact of general rate
increases placed into effect by two subsidiaries in the latter part of 1992
contributed favorably to 1993 operating results, but were offset by higher costs
of operations.
 
       OPERATING REVENUES
 
Operating revenues of the gas distribution operations in 1995 declined $60.4
million from the prior year. Gas sales revenues declined $81.0 million as lower
average sales prices more than offset the impact of higher sales volumes. The
lower average sales prices were the result of lower unit purchased gas costs
reflected in the rates charged to customers. Rate increases in late 1994 and in
1995 (see "State Regulatory Issues"), however, helped hold down the decline in
sales revenues. Gas transportation and storage revenues increased $20.4 million
in 1995 due to both increased volumes and rates.
 
Revenues of the gas distribution operations rose $31.7 million in 1994, a 2
percent increase compared with 1993. Gas sales revenues rose $23.6 million due
to increases in the average sales price received from residential and commercial
customers, partially offset by reduced sales volumes due to warmer than normal
weather. Gas sales were impacted by general rate increases placed into effect in
the latter part of the year at three of the distribution subsidiaries and the
full year impact of a general rate increase that went into effect in late 1993
at Hope Gas, Inc. (Hope Gas). Gas transportation and storage revenues were up
$6.5 million, reflecting increased transportation volumes, while other operating
revenues increased $1.6 million.
 
       DISTRIBUTION THROUGHPUT
 
Since distribution sales largely represent retail sales for space heating,
changes in sales volumes from one period to another are primarily a function of
the weather. In addition to sales service, the distribution operations provide
gas transportation services to a wide range of customers, primarily commercial
and industrial end users. Therefore, the volume of gas transported can be
affected by changes in both economic and market conditions.
 
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
DISTRIBUTION THROUGHPUT                                              1995       1994       1993
-----------------------------------------------------------------------------------------------
                                                                     (In Billion Cubic Feet)
<S>                                                                <C>        <C>        <C>
Sales.........................................................      289.9      285.0      297.8
Transportation................................................      164.8      151.1      145.4
                                                                    -----      -----      -----
     Throughput...............................................      454.7      436.1      443.2
                                                                    =====      =====      =====
-----------------------------------------------------------------------------------------------
</TABLE>
 
Gas sales volumes were up 2 percent in 1995, reflecting colder weather and the
net addition of about 24,800 residential and commercial customers. Residential
and commercial gas sales increased 6.6 Bcf and .4 Bcf, respectively, compared to
1994. While industrial sales volumes declined 2.1 Bcf, transportation volumes to
those customers increased 9.8 Bcf. Gas transported for commercial customers was
29.8 Bcf in 1995, up 5.4 Bcf compared to 1994. Transportation to off-system
customers declined 1.5 Bcf in 1995.
 
Warmer weather was the primary factor in the decline in gas sales during 1994,
while transportation volumes were up 4 percent. Although the impact was
partially offset by the net addition of about 22,500 customers, the weather was
3 percent warmer than in 1993, resulting in lower space-heating sales.
Residential and commercial gas sales volumes declined by 6.4 Bcf and 3.3 Bcf,
respectively, compared
 
                                       29
<PAGE>   32
 
ITEM 7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
            RESULTS OF OPERATIONS (Continued)
 
to 1993. Industrial sales volumes were down 3.1 Bcf to 9.4 Bcf, while
transportation volumes were up 5.2 Bcf to 121.1 Bcf. Gas transported for
commercial customers was 24.4 Bcf in 1994, up 3.3 Bcf, while transportation to
off-system customers declined 2.8 Bcf to 5.6 Bcf in 1994.
 
TRANSMISSION
 
"Transmission" includes the results of the gas transmission, storage, by-product
and certain other activities of CNG Transmission and, prior to April 1, 1995,
the activities of CNG Storage Service Company (CNG Storage). CNG Storage was
formed primarily to engage in the sale, lease or brokerage of gas storage
capacity obtained from third parties including the sale or lease of base gas.
The results of CNG Storage for 1995 and prior periods were not a significant
portion of the transmission operations. Gas and oil production activities of CNG
Transmission are included in exploration and production operations.
 
Changing regulatory policies intended to increase competition in the natural gas
industry have been the principal factor affecting the transmission operations
over the past several years. Beginning with open access transportation and
culminating with the significant service restructuring required by FERC Order
636, the role of CNG Transmission has changed from that of primarily a merchant,
or wholesaler, of gas to one that provides a range of gas transportation,
storage, and other related services.
 
With its implementation of Order 636 effective October 1, 1993, CNG Transmission
abandoned its traditional sales service which consisted of various elements of
gas sales, transportation and storage that were offered and priced as a single
bundled service. Customers now have even greater access to the Company's
pipeline and storage capacity, together with a range of options available with
respect to gas transportation and storage services.
 
       OPERATING INCOME BEFORE INCOME TAXES
 
Operating income before income taxes of the gas transmission operations
increased $4.1 million in 1995 to $150.4 million. Excluding workforce reduction
charges totaling $6.0 million, operating income before income taxes for 1995
would have been $156.4 million. Higher rates resulting from CNG Transmission's
latest general rate filing and cost controls were the major factors for the
improved results in 1995.
 
Operating income before income taxes increased $2.9 million, or 2 percent, in
1994 to $146.3 million. Operating results for 1994 reflect the first full year
of applying the straight fixed variable rate design under which operating income
is less influenced by changes in throughput than in the past. Significant
factors affecting 1994 operating results included increased transportation and
storage service revenues, competition from other pipelines, and higher operating
costs not yet reflected in rates.
 
Operating results for 1993 include the impact of expanded service to customers
in the Northeast as a result of the Company's pipeline construction program,
increased throughput to affiliated distribution companies, and higher gas
storage service and by-product revenues. Colder weather and, to a lesser extent,
sales of gas from storage inventory and certain other steps taken to facilitate
the transition to Order 636 also contributed to the 1993 results.
 
       OPERATING REVENUES
 
Total operating revenues of the gas transmission operations increased $11.7
million in 1995 to $471.0 million. Gas transportation and storage revenues
increased $27.4 million in 1995 due primarily to higher transportation revenues,
which increased $24.3 million as higher rates more than offset slightly lower
transport volumes. Revenues from the sale of by-products declined $10.2 million,
due to the overall decline in volumes of products sold.
 
                                       30
<PAGE>   33
 
ITEM 7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
            RESULTS OF OPERATIONS (Continued)
 
Total operating revenues declined by $524.5 million in 1994 to $459.3 million.
CNG Transmission abandoned its traditional sales service pursuant to the October
1, 1993 implementation of Order 636. Gas sales revenues in 1993 were $631.1
million. Increases during 1994 in transportation and storage service revenues of
$92.9 million and $22.9 million, respectively, reflected the impact of the first
full year of services provided under Order 636. Revenues from the sale of
by-products declined by $1.4 million in 1994 as a result of lower prices.
 
       TRANSMISSION THROUGHPUT
 
The changing regulatory environment has created a number of opportunities for
pipeline companies to expand and serve new markets. The Company has taken
advantage of selected market expansion opportunities, concentrating the efforts
toward potentially high-volume, weather-sensitive markets and areas with growing
power generation needs located primarily in the Northeast and along the East
Coast. This expansion takes advantage of the Company's network of underground
storage facilities and the location and nature of its gridlike pipeline system
as a link between the country's major longline gas pipelines and the increasing
energy demands of East Coast markets.
 
Variations in weather conditions can also have a significant impact on the
throughput of the transmission operations, since a substantial portion of the
gas deliveries of these operations is ultimately used by space-heating
customers. Also, transmission operations provide transportation services to a
wide range of customers, including commercial and industrial end users, electric
power generators, and local utility companies. Therefore, the volume of gas
transported can also be affected by changes in economic and market conditions.
 
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
TRANSMISSION THROUGHPUT                                              1995       1994       1993
-----------------------------------------------------------------------------------------------
                                                                     (In Billion Cubic Feet)
<S>                                                                <C>        <C>        <C>
Sales.........................................................         --         --      100.1
Transportation................................................      744.0      748.4      610.9
                                                                    -----      -----      -----
     Throughput*..............................................      744.0      748.4      711.0
                                                                    =====      =====      =====
-----------------------------------------------------------------------------------------------
<FN>
 
* Includes intercompany activity.
</TABLE>
 
Total throughput for the gas transmission operations, consisting entirely of
transportation volumes, was 744.0 Bcf in 1995, down slightly compared with 1994.
First quarter 1995 throughput was lower than the prior year due to warmer
weather in that period, while throughput was up for the balance of 1995 compared
to 1994.
 
The Company's transmission operations total throughput of 748.4 Bcf in 1994
exceeded 1993's record throughput level by 5 percent. The 1994 throughput
consisted solely of transportation volumes as CNG Transmission abandoned its
traditional sales service with the October 1, 1993 implementation of Order 636.
The increase of 137.5 Bcf of transportation volumes compared to 1993 occurred
mainly in the first quarter of 1994 consistent with the cold weather experienced
early in the year.
 
EXPLORATION AND PRODUCTION
 
"Exploration and production" includes the results of CNG Producing Company (CNG
Producing) and the gas and oil production activities of CNG Transmission.
 
       OPERATING INCOME BEFORE INCOME TAXES
 
The exploration and production operations reported an operating loss before
income taxes of $200.5 million in 1995, compared with operating income before
income taxes of $34.0 million in 1994.
 
                                       31
<PAGE>   34
 
ITEM 7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
            RESULTS OF OPERATIONS (Continued)
 
The loss for 1995 reflects the first quarter non-cash charge of $226.2 million
for the impairment of gas and oil producing properties and workforce reduction
charges during 1995 totaling $7.7 million. Excluding these special items,
operating income before income taxes would have been $33.4 million in 1995. The
impact of continued low gas wellhead prices and lower gas and oil production
slightly offset the favorable impact of higher oil wellhead prices, a $7.5
million reduction in production-related expenses, and reductions in overhead
costs in 1995. In addition, depreciation and amortization expense was $32.1
million lower in 1995 resulting from the impairment of gas and oil producing
properties, the effect of gas and oil reserve additions, and lower production.
Reserves equivalent to 203 Bcf of gas were added in 1995.
 
Exploration and production operating income before income taxes in 1994
decreased $13.3 million compared to 1993. The effect of the decline in total
operating revenues due to lower prices and production was partially offset by
decreases in royalty expense and depreciation and amortization of $9.4 million
and $21.2 million, respectively. The lower level of royalty expense is
attributable primarily to reduced gas and oil production during 1994. Lower
production, together with the recognition of additional proved gas and oil
reserves in the Gulf of Mexico, resulted in lower depreciation and amortization
expense for 1994. Reserves equivalent to 190 Bcf of gas at Viosca Knoll 826, a
deep-water project in the Gulf of Mexico in which the Company holds a 50 percent
interest, were added in 1994 and represent the largest single addition of
reserves in the Company's history.
 
In 1993, operating income was $47.3 million, up $8.5 million, as higher wellhead
prices for natural gas and slightly higher gas production more than offset lower
oil prices and production and lower margins on the brokering of gas.
 
       GAS AND OIL PRODUCTION AND PRICES
 
The following table sets forth the Company's gas and oil production and average
wellhead prices for the exploration and production operations for the last three
years:
 
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------
PRODUCTION                                                        1995         1994         1993
------------------------------------------------------------------------------------------------
<S>                                                           <C>          <C>          <C>
GAS (BCF)
Nonregulated.............................................        102.6        113.7        123.5
Regulated*...............................................          4.6          5.8          6.0
                                                               -------      -------      -------
  Total..................................................        107.2        119.5        129.5
                                                               =======      =======      =======
OIL (000 BBLS)
Nonregulated.............................................      3,131.7      3,333.0      3,906.8
Regulated*...............................................         17.2         23.8         29.1
                                                               -------      -------      -------
  Total..................................................      3,148.9      3,356.8      3,935.9
                                                               =======      =======      =======
AVERAGE WELLHEAD PRICES
(NONREGULATED ONLY)
Gas (per Mcf)............................................       $ 1.89       $ 2.16       $ 2.24
Oil (per Bbl)............................................       $16.04       $14.45       $15.66
------------------------------------------------------------------------------------------------
<FN>
 
* Cost-of-service.
</TABLE>
 
Consistent with prices nationwide, the Company's gas wellhead prices in 1995
were below prior year levels for most of the period as the average gas price of
$1.89 per Mcf was $.27 less than the 1994 price. As a result of continued weak
gas prices, the Company voluntarily shut in a portion of its production at
various times during 1995 which, in addition to normal declines at certain
properties, resulted in a decline in production compared to 1994. While average
oil wellhead prices rose $1.59 per barrel in 1995, oil production was lower than
1994 due primarily to normal production declines at older properties.
 
                                       32
<PAGE>   35
 
ITEM 7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
            RESULTS OF OPERATIONS (Continued)
 
Gas wellhead prices were strong in the first quarter of 1994 but declined and
remained considerably below 1993 levels for most of the balance of 1994. The
Company's average gas price was $2.16 per Mcf in 1994, down $.08 from 1993. The
low prices for natural gas that prevailed nationwide during most of 1994 were
the basis for the Company's decision to shut in a portion of its offshore
production during the latter part of the year, resulting in lower gas production
for the year. The Company's average oil price declined 8 percent in 1994,
consistent with the continued overall decline in world oil prices. The lower oil
production during 1994 was due largely to normal production declines at older
properties, in addition to the partial shut-in of production.
 
       OPERATING REVENUES
 
Total operating revenues for the exploration and production operations decreased
$127.9 million in 1995, to $361.5 million. Gas sales revenues declined $134.0
million, reflecting the continued low level of gas wellhead prices and lower
production compared to 1994. Revenues from oil and condensate production and
brokering increased $10.5 million in 1995. Revenues from oil brokering were up
$8.8 million due to both higher volumes sold and higher rates, while revenues
from oil and condensate production were up $1.7 million as higher rates more
than offset the effect of lower volumes.
 
Total operating revenues declined $47.0 million in 1994. Gas sales revenues
decreased $23.0 million primarily due to lower prices received during 1994. Gas
sales volumes were flat compared with 1993 as lower sales of produced gas were
offset by an increase in brokered gas volumes. Oil and condensate revenues were
down $20.3 million which reflected lower volumes and prices for both oil
production and brokering activities. Revenues from oil and condensate production
decreased $13.2 million, while revenues from oil brokering were down $7.1
million. Other revenues declined $3.7 million due principally to business
interruption insurance reimbursements related to Hurricane Andrew received in
1993.
 
ENERGY MARKETING SERVICES
 
"Energy marketing services" represents the results of CNG Energy Services, CNG
Power Company (CNG Power), CNG Power Services Corporation (CNG Power Services),
and CNG Storage. These subsidiaries, which are under a single management team,
were reported as one business component in 1995. The results for these
subsidiaries, except CNG Storage, were included in the "Other" component prior
to 1995. CNG Storage was included in the "Transmission" component prior to April
1,1995.
 
CNG Energy Services markets Company-owned gas production and arranges gas
supplies, transportation, storage and related services for customers. CNG Power
holds the Company's ownership interests in seven independent power plants. CNG
Power Services purchases and resells electricity at market-based rates.
 
Energy marketing services reported an operating loss before income taxes of $5.7
million in 1995, which includes workforce reduction charges of $.5 million. In
addition to depressed gas margins throughout the year, CNG Energy Services
recognized a $5.3 million pretax charge in December 1995 in connection with a
mark-to-market valuation of exchange-traded futures contracts used to manage
price risk exposure related to its stored gas inventories. However, income from
the physical sale of gas from storage in 1996 is expected to generally offset
the effect of this charge. Total throughput for this component was 570.8 Bcf in
1995. Income recognized in connection with CNG Power's investments in 1995
totaled $3.9 million. This amount is not included in the operating loss before
income taxes but is reflected in "Other income" for the component.
 
                                       33
<PAGE>   36
 
ITEM 7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
            RESULTS OF OPERATIONS (Continued)
 
LIMITATION ON CAPITALIZED COSTS
 
As indicated in Note 1 to the consolidated financial statements, CNG Producing
and CNG Transmission follow the full cost method of accounting for their gas and
oil producing activities prescribed by the Securities and Exchange Commission
(SEC).
 
Due primarily to the decline in wellhead gas prices, the Company was required
under the SEC full cost rules to recognize an impairment of its gas and oil
producing properties at March 31, 1995. The non-cash charge amounted to $226.2
million and reduced 1995 net income by $145.0 million. No additional impairment
of these properties was required during the remainder of 1995.
 
There are a number of factors, including prices, that determine whether or not
an impairment is required. Gas wellhead prices were strong during the fourth
quarter of 1995, and continued to be firm in the early part of 1996 due
primarily to higher demand caused by the colder weather and reduced storage
inventory levels. However, since gas wellhead prices are subject to sudden
fluctuations, the impairment of these gas and oil properties is a possibility at
any quarterly measurement date, unless other factors such as lower production
costs or proved reserve additions mitigate the impact of the price decline.
 
INTERNATIONAL ACTIVITIES
 
In November 1994, CNG Energy Services formed a marketing alliance with two
Canadian firms, Hydro-Quebec and Noverco. The alliance offers energy services to
customers throughout the northeastern and midwestern United States and eastern
Canada. In June 1995, the companies signed an agreement to create a
partnership--the Energy Alliance Partnership--to conduct alliance business. This
agreement is subject to SEC and other regulatory approvals.
 
In November 1995, the Company announced the formation of a strategic alliance
with EnergyAustralia (formerly known as MetNorth Energy), Australia's largest
electric utility, to assist EnergyAustralia in developing its natural gas
marketing capabilities and to jointly identify and develop energy infrastructure
projects in Australia and Asia.
 
In January 1996, the Company formed a new subsidiary, CNG International
Corporation (CNG International). The purpose of CNG International is to engage
in energy-related activities outside the United States, including activities
under the EnergyAustralia alliance. The financing of CNG International is
subject to SEC approval.
 
FEDERAL AND STATE REGULATORY MATTERS
 
       FERC ORDER 636
 
FERC Order 636, issued in 1992, allows pipelines to recover 100 percent of all
prudently incurred costs resulting from the transition to the new rules
(transition costs). The FERC has identified four types of transition costs: (1)
purchased gas costs that would have been recovered from customers through the
purchased gas adjustment provisions of previous tariffs, but which are
unrecovered at the termination of "bundled" services; (2) gas supply realignment
(GSR) costs required to reform or terminate contracts to purchase gas from
producers; (3) stranded costs, which are the costs of facilities or
transportation arrangements no longer necessary or uneconomic after
restructuring; and (4) the costs of installing new facilities that may be
required to comply with the new rules.
 
CNG Transmission received FERC approval to implement Order 636 effective October
1, 1993, in accordance with the terms of a comprehensive stipulation and
agreement (Settlement) reached with customers and others. With FERC approval,
CNG Transmission direct billed and began collecting transition costs amounting
to $177.9 million and $9.8 million in December 1993 and August 1994,
 
                                       34
<PAGE>   37
 
ITEM 7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
            RESULTS OF OPERATIONS (Continued)
 
respectively. During 1995, CNG Transmission made refunds to its customers and
affiliates of $9.1 million in connection with the prior direct billings.
 
As part of the Settlement, CNG Transmission agreed to absorb up to $3.5 million
of GSR costs. GSR costs, however, have been minimized since certain of the
distribution subsidiaries agreed to the assignment from CNG Transmission of its
Appalachian gas purchase contracts in consideration for favorable cost
allocation provisions contained in the Settlement.
 
The Settlement allows CNG Transmission to file with the FERC for rate increases
to recover both stranded costs and new facilities costs. The Settlement also
provides CNG Transmission additional rights to defer recognition of certain
stranded costs pending rate case review. Parties to the Settlement have also
agreed not to challenge certain construction projects that CNG Transmission may
determine will assist it in rendering unbundled services. In its December 30,
1993, general rate filing with the FERC, CNG Transmission requested recovery of
$9.2 million of stranded facilities costs, but subsequently reduced that amount
to $4.3 million to reflect actual amounts incurred. In a December 30, 1994
filing, CNG Transmission requested recovery of an additional $.7 million of
stranded upstream transportation service costs. The recovery of these stranded
costs was included in the settlement agreement approved by the FERC on November
29, 1995 regarding its December 30, 1993 general rate filing.
 
Although a final overall estimate of new facilities costs to be incurred by CNG
Transmission has not yet been determined, such costs may approach $30 million.
 
Based on management's current estimates, the operating environment under Order
636 and any uncertainties pertaining to the recovery of transition costs should
not have a material adverse effect on the Company's financial position, results
of operations or cash flows. Reference is made to Note 2 to the consolidated
financial statements for additional information regarding Order 636 transition
costs.
 
       CNG TRANSMISSION
 
On November 29, 1995, the FERC approved a settlement agreement filed by CNG
Transmission in connection with its December 30, 1993 general rate filing. The
settlement resolves the outstanding issues in the case and results in an annual
revenue increase of $40 million, retroactive to July 1, 1994, the date new rates
went into effect subject to refund. The settlement reflects an imputed return on
equity of 11.30 percent. Customer refunds resulting from the settlement totaling
$81.5 million were made in December 1995 with an additional $4.8 million
expected to be refunded in the first quarter of 1996. In its filing, CNG
Transmission had requested a $106.6 million increase in annual revenues and a
return on equity of 14.00 percent.
 
       STATE REGULATORY ISSUES
 
On August 3, 1995, the Pennsylvania Public Utility Commission approved a
settlement agreement filed by Peoples Natural Gas covering its February 1, 1995
general rate filing. The approved settlement includes an $8.0 million annual
revenue increase with new rates effective August 4, 1995. In its filing, Peoples
Natural Gas had originally requested a $32.8 million increase in annual
revenues.
 
On September 1, 1995, Virginia Natural Gas submitted an expedited rate filing
with the Virginia State Corporation Commission (VSCC) requesting an annual
revenue increase of $7.2 million. The new rates went into effect, subject to
refund, on October 1, 1995. On February 23, 1996, Virginia Natural Gas requested
approval from the VSCC to withdraw this rate filing. Pending VSCC approval,
customer refunds related to the filing will be made later in 1996.
 
On October 26, 1995, the Public Service Commission of West Virginia approved a
settlement agreement filed by Hope Gas in connection with its January 4, 1995
general rate filing. The new rates became effective November 1, 1995. The
approved settlement agreement increased base rates but eliminated
 
                                       35
<PAGE>   38
 
ITEM 7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
            RESULTS OF OPERATIONS (Continued)
 
the purchased gas cost adjustment mechanism for the three-year period covered by
the settlement. Therefore, any increase or decrease in gas costs over the base
amount included in rates will not be passed on to customers during the
settlement period.
 
On November 8, 1995, a $6.2 million annual revenue increase became effective at
The East Ohio Gas Company in connection with the November 3, 1994 settlement of
its general rate case, as approved by the Public Utilities Commission of Ohio.
This increase is in addition to the $62.4 million annual revenue increase that
became effective November 8, 1994.
 
On January 30, 1996, the VSCC issued a final order in connection with Virginia
Natural Gas' September 1, 1994 general rate filing. The order results in an
annual revenue increase of $6.1 million, retroactive to October 1, 1994, the
date new rates went into effect subject to refund. Customer refunds resulting
from the order will be made in the first half of 1996. The order reflects an
imputed return on equity of 11.3 percent. In its filing, Virginia Natural Gas
had requested a $9.9 million increase in annual revenues and a return on equity
of 11.75 percent.
 
ENVIRONMENTAL MATTERS
 
The Company is subject to various federal, state and local laws and regulations
relating to the protection of the environment. These laws and regulations govern
both current and future operations and potentially extend to plant sites
formerly owned or operated by the subsidiaries, or their predecessors.
 
Reference is made to Note 16 to the consolidated financial statements, page 63,
for a detailed description of environmental matters.
 
Estimates of liability in the environmental area are based on current
environmental laws and regulations and existing technology. The exact nature of
environmental issues which the Company may encounter in the future cannot be
predicted. Additional environmental liabilities may result in the future as more
stringent environmental laws and regulations are implemented and as the Company
obtains more specific information about its existing sites and production
facilities. At present, no estimate of any such additional liability, or range
of liability amounts, can be made. However, the amount of any such liabilities
could be material.
 
EFFECTS OF INFLATION
 
Although inflation rates have been moderate in recent years, any change in price
levels has an effect on operating results due to the capital intensive and
regulated nature of the Company's major business components. The Company
attempts to minimize the effects of inflation through cost control, productivity
improvements and regulatory actions where appropriate.
 
FINANCIAL CONDITION
 
DIVIDEND AND COMMON STOCK MATTERS
 
In December 1995, the Board of Directors continued the quarterly dividend on the
common stock at 48.5 cents a share. Total dividends paid to common shareholders
in 1995 were $180.8 million compared with $180.4 million in 1994 and $178.1
million in 1993.
 
During 1995, a total of 567,818 original issue shares were issued through
various Company-sponsored plans, including 216,766 shares acquired by employees
through the exercise of outstanding stock options.
 
Under the Company's stock repurchase plan, up to 4 million shares of the
outstanding common stock can be repurchased. The shares may be purchased in the
open market from time-to-time, depending on
 
                                       36
<PAGE>   39
 
ITEM 7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
            RESULTS OF OPERATIONS (Continued)
 
market conditions. The Company may also acquire shares of its common stock
through certain provisions of the 1991 Stock Incentive Plan and the Long-Term
Incentive Plan. The shares repurchased or acquired are held as treasury stock
and are available for reissuance for general corporate purposes or in connection
with various employee benefit plans. No treasury shares were held by the Company
at December 31, 1994. During 1995, no open market purchases were made by the
Company. The Company acquired 17,351 shares in 1995 through the provisions of
its employee incentive plans at a cost of $634,000, or an average price of
$36.54 a share. All of these shares were sold before year-end to the Company's
Thrift Plans.
 
CAPITAL SPENDING
 
The current capital budget for 1996 is estimated at $455.2 million, a 4 percent
increase compared with total capital spending in 1995. The estimated 1996 budget
has been allocated as follows: distribution, $147.6 million; transmission, $89.3
million; exploration and production, $180.6 million; energy marketing services,
$33.2 million; and corporate and other, $4.5 million. The increased level of
capital expenditures anticipated for 1996 reflects slightly higher spending for
exploration and production operations, including funds for development of Viosca
Knoll 826, the Company's second deep-water project in the Gulf of Mexico.
Transmission and distribution operations expenditures will primarily be limited
to spending for enhancements and improvements in the pipeline system and related
facilities. Expenditures for the energy marketing services component include
funds for the development, through partnerships with other energy companies, of
offshore gas and oil gathering systems for two production areas in the Gulf of
Mexico. The "corporate and other" category includes expenditures to upgrade
information systems technology.
 
Funds required for the capital spending program, as well as for other general
corporate purposes, are expected to be obtained principally from internal cash
generation. Although the Company does not expect to require long-term financing
in 1996 to support capital spending, it may turn to the market to take advantage
of other opportunities and to increase its financial flexibility.
 
CAPITAL RESOURCES AND LIQUIDITY
 
Because of the seasonal nature of the regulated subsidiaries' heating business,
a substantial portion of the Company's cash receipts are realized in the first
half of the year. However, cash requirements for capital expenditures,
dividends, debt retirements and other working capital needs do not track this
pattern of cash receipts. Consequently, additional cash needs are satisfied
through the sale of short-term commercial paper notes or by the issuance of
long-term debt. As shown in the Consolidated Statement of Cash Flows, net cash
provided by operating activities was $552.7 million, $631.3 million and $470.9
million for the years 1995, 1994 and 1993, respectively. Lower gas wellhead
prices and rate-related refunds made to customers were the principal reasons for
the lower cash flows from operations in 1995. Higher rates put into effect at
CNG Transmission during the year and the recovery of Order 636 transition costs
contributed to the increase in operating cash flows in 1994.
 
During April 1995, the Company sold $150 million of 7 3/8% Debentures Due April
1, 2005. The net proceeds from the sale were used to finance, in part, 1995
capital expenditures and to reduce short-term debt.
 
The Company has shelf registrations with the SEC for the sale of up to $350
million of debt securities. The amount and timing of any future sale of these
debt securities will depend primarily on the ability of the Company to issue
senior debt under the financing restrictions contained in the Company's
indentures (see Note 13 to the consolidated financial statements, page 61,
regarding these restrictions). Any future sale will also depend on capital
requirements, including financing necessary to enable the Company to pursue
asset acquisition opportunities, and financial market conditions.
 
                                       37
<PAGE>   40
 
ITEM 7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
            RESULTS OF OPERATIONS (Concluded)
 
The Company's embedded long-term debt cost, excluding current maturities, at
year-end 1995 was 7.69 percent, compared with 7.74 percent for 1994 and 7.75
percent for 1993. The long-term debt to capitalization ratio was 38.7 percent at
the end of 1995, and 34.5 percent and 34.7 percent at year-end 1994 and 1993,
respectively. Under the provisions of the indenture covering the Company's
outstanding senior debenture issues, the ratio cannot exceed 60 percent. The
Company's senior debentures are rated A1 by Moody's Investors Service, AA- by
Standard & Poor's, AA- by Duff and Phelps, and AA by Fitch Investors Service.
 
At December 31, 1995, the Company had two short-term credit agreements with
groups of banks, for $475 million and $300 million, which replaced prior credit
agreements effective June 30, 1995. The Company made no borrowings under these
agreements during 1995 and there were no amounts outstanding under any credit
agreements at December 31, 1995 or 1994.
 
The Company utilizes short-term borrowings to finance gas inventories and other
working capital requirements. Funds from the sale of commercial paper notes were
used for these purposes in 1995, of which $336 million was outstanding at
year-end. The Company may utilize unused portions of its credit agreements to
provide support for commercial paper notes.
 
In the normal course of business, the nonregulated subsidiaries utilize
exchange-traded commodity futures and options contracts and derivative financial
instruments to manage exposure to price risk in connection with the production,
purchase and sale of natural gas and oil, and for stored gas inventories. The
use of futures and options contracts and derivative financial instruments
exposes the Company to market risk and credit risk. Market risk represents the
potential loss that can be caused by a change in the market value of a
particular commitment. Although the use of exchange-traded and over-the-counter
instruments generally reduces market risk exposure due to unfavorable price
fluctuations, risk management activities, while not significant, can result in
the assumption of a limited degree of price risk in certain isolated
transactions. Credit risk relates to the risk of loss that the Company would
incur as a result of nonperformance by counterparties pursuant to the terms of
their contractual obligations. The Company does not have a significant exposure
to any individual counterparty to its energy price risk management activities.
Management has operating procedures in place to evaluate market and credit risks
and believes that the Company's exposure to risks associated with
exchange-traded futures and options contracts and derivative financial
instruments is not material in relation to the Company's financial position,
results of operations or cash flows. Reference is made to Notes 1 and 15 to the
consolidated financial statements, pages 45 and 62, regarding energy price risk
management activities.
 
SUMMARY OF FINANCIAL DATA
 
The Company's Summary of Financial Data is on page 23.
 
                                       38
<PAGE>   41
 
ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
SUPPLEMENTARY DATA
 
This information is included in the Notes to Consolidated Financial Statements
and reference is made thereto as follows: Gas and Oil Producing Activities--Note
19(A), page 68; Quarterly Financial Data-- Note 19(B), page 72.
 
FINANCIAL STATEMENTS
 
                                     INDEX
 
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------
                                                                                        Page
--------------------------------------------------------------------------------------------
<S>                                                                                 <C>
Report of Independent Accountants...............................................         40
Consolidated Statement of Income for the Years 1993 through 1995................         41
Consolidated Balance Sheet at December 31, 1994 and 1995........................         42
Consolidated Statement of Cash Flows for the Years 1993 through 1995............         44
Notes to Consolidated Financial Statements......................................         45
Schedule II--Valuation and Qualifying Accounts..................................     Note 2
<FN>
 
Notes:
  (1) Schedules I, III, IV, and V have been excluded because they are not
      applicable.
  (2) Omitted inasmuch as amounts involved are not significant.
 
--------------------------------------------------------------------------------------------
</TABLE>
 
                                       39
<PAGE>   42
 
ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
 
                       REPORT OF INDEPENDENT ACCOUNTANTS
 
To the Board of Directors and Stockholders of
Consolidated Natural Gas Company
 
In our opinion, the consolidated financial statements listed in the accompanying
index on page 39 present fairly, in all material respects, the financial
position of Consolidated Natural Gas Company and subsidiaries (the Company) at
December 31, 1995 and 1994, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1995, in
conformity with generally accepted accounting principles. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
generally accepted auditing standards which require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the opinion expressed
above.
 
As discussed in Note 1 to these consolidated financial statements, the Company
adopted Statement of Financial Accounting Standards No. 109, "Accounting for
Income Taxes," in 1993.
 
PRICE WATERHOUSE LLP
 
600 Grant Street
Pittsburgh, Pennsylvania 15219-9954
February 20, 1996
 
                                       40
<PAGE>   43
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
                        CONSOLIDATED STATEMENT OF INCOME
 
 <TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------
For the Years Ended December 31,                                       1995           1994           1993
---------------------------------------------------------------------------------------------------------
                                                                          (Thousands of Dollars)
<S>                                                              <C>            <C>            <C>
OPERATING REVENUES
Regulated gas sales..........................................    $1,597,379     $1,679,235     $2,073,187
Nonregulated gas sales.......................................       997,724        723,626        541,849
                                                                 ----------     ----------     ----------
    Total gas sales..........................................     2,595,103      2,402,861      2,615,036
Gas transportation and storage...............................       456,370        409,632        333,332
Other........................................................       255,852        223,535        235,717
                                                                 ----------     ----------     ----------
    Total operating revenues (Note 2)........................     3,307,325      3,036,028      3,184,085
                                                                 ----------     ----------     ----------
OPERATING EXPENSES
Purchased gas................................................     1,590,137      1,424,020      1,594,373
Transport capacity and other purchased products..............       153,577        107,094         79,001
Operation expense (Note 4)...................................       653,731        600,421        590,459
Maintenance..................................................        85,881         89,154         87,207
Depreciation and amortization (Note 3).......................       256,636        279,317        294,648
Impairment of gas and oil producing properties (Note 3)......       226,209             --             --
Taxes, other than income taxes...............................       191,698        192,617        181,053
                                                                 ----------     ----------     ----------
    Subtotal.................................................     3,157,869      2,692,623      2,826,741
                                                                 ----------     ----------     ----------
    Operating income before income taxes.....................       149,456        343,405        357,344
Income taxes (Note 7)........................................         2,943         82,427         99,906
                                                                 ----------     ----------     ----------
    Operating income.........................................       146,513        260,978        257,438
                                                                 ----------     ----------     ----------
OTHER INCOME (DEDUCTIONS)
Interest revenues............................................         9,095          5,006          3,317
Write-down of coal properties (Note 3).......................       (31,266)            --             --
Other-net....................................................         1,665          4,688          7,214
                                                                 ----------     ----------     ----------
    Total other income (deductions)..........................       (20,506)         9,694         10,531
                                                                 ----------     ----------     ----------
    Income before interest charges...........................       126,007        270,672        267,969
                                                                 ----------     ----------     ----------
INTEREST CHARGES
Interest on long-term debt...................................        95,823         88,788         85,265
Other interest expense.......................................        14,732          7,992          4,995
Allowance for funds used during construction.................        (5,892)        (9,279)       (10,785)
                                                                 ----------     ----------     ----------
    Total interest charges...................................       104,663         87,501         79,475
                                                                 ----------     ----------     ----------
Income before cumulative effect of change
  in accounting principle....................................        21,344        183,171        188,494
Cumulative effect of applying SFAS No. 109 (Note 7)..........            --             --         17,422
                                                                 ----------     ----------     ----------
NET INCOME...................................................    $   21,344     $  183,171     $  205,916
                                                                  =========      =========      =========
    Earnings per share of common stock
      Income before cumulative effect of change
        in accounting principle..............................          $.23          $1.97          $2.03
      Cumulative effect of applying SFAS No. 109 (Note 7)....            --             --            .19
                                                                 ----------     ----------     ----------
      Net Income.............................................          $.23          $1.97          $2.22
                                                                  =========      =========      =========
    Average common shares outstanding (thousands)............        93,246         93,000         92,808
<FN>
 
---------------------------------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
 
                                       41
<PAGE>   44
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
                           CONSOLIDATED BALANCE SHEET
 
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
At December 31,                                                        1995            1994
----------------------------------------------------------------------------------------------
                                                                     (Thousands of Dollars)
<S>                                                                <C>             <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT (Note 3)
Gas utility and other plant....................................    $ 4,710,086     $ 4,546,753
Accumulated depreciation and amortization......................     (1,785,965)     (1,686,788)
                                                                   -----------     -----------
       Net gas utility and other plant.........................      2,924,121       2,859,965
                                                                   -----------     -----------
Exploration and production properties..........................      3,219,264       3,130,203
Accumulated depreciation and amortization......................     (2,230,980)     (1,963,522)
                                                                   -----------     -----------
       Net exploration and production properties...............        988,284       1,166,681
                                                                   -----------     -----------
       Net property, plant and equipment.......................      3,912,405       4,026,646
                                                                   -----------     -----------
CURRENT ASSETS
Cash and temporary cash investments............................         36,277          31,923
Accounts receivable
  Customers....................................................        522,391         407,145
  Unbilled revenues and other..................................        144,253         146,653
  Allowance for doubtful accounts..............................        (10,306)         (7,507)
Inventories, at cost
  Gas stored--current portion (Note 8).........................        112,429         190,196
  Materials and supplies (average cost method).................         35,815          35,072
Unrecovered gas costs (Note 2).................................         25,123          13,135
Deferred income taxes--current (Note 7)........................         20,993          60,103
Prepayments and other current assets...........................        181,686         188,019
                                                                   -----------     -----------
       Total current assets....................................      1,068,661       1,064,739
                                                                   -----------     -----------
REGULATORY AND OTHER ASSETS
Unamortized abandoned facilities (Note 9)......................         28,672          40,955
Other investments..............................................         60,939          54,682
Deferred charges and other assets (Notes 2, 4, 6, 7 and 16)....        347,616         331,651
                                                                   -----------     -----------
       Total regulatory and other assets.......................        437,227         427,288
                                                                   -----------     -----------
       Total assets............................................    $ 5,418,293     $ 5,518,673
                                                                   ===========     ===========
<FN>
 
----------------------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
 
                                       42
<PAGE>   45
 
ITEM 8.
(Cont.)
 
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
At December 31,                                                        1995            1994
----------------------------------------------------------------------------------------------
                                                                     (Thousands of Dollars)
<S>                                                                <C>             <C>
STOCKHOLDERS' EQUITY AND LIABILITIES

CAPITALIZATION
Common stockholders' equity (Note 10)
  Common stock, par value $2.75 per share,
     200,000,000 authorized shares
     Issued, 1995--93,591,623 shares, 1994--93,027,847
     shares....................................................    $   257,377     $   255,827
  Capital in excess of par value...............................        478,535         458,628
  Retained earnings (Note 12)..................................      1,309,906       1,469,879
                                                                   -----------     -----------
       Total common stockholders' equity.......................      2,045,818       2,184,334
Long-term debt (Note 13).......................................      1,291,811       1,151,973
                                                                   -----------     -----------
       Total capitalization....................................      3,337,629       3,336,307
                                                                   -----------     -----------
CURRENT LIABILITIES
Current maturities on long-term debt...........................         10,250           4,000
Commercial paper (Note 14).....................................        336,000         440,000
Accounts payable...............................................        410,296         357,611
Estimated rate contingencies and refunds (Note 2)..............         59,363          83,404
Amounts payable to customers...................................         40,315          96,140
Taxes accrued..................................................        114,335          94,413
Dividends declared.............................................         45,392          45,119
Other current liabilities......................................         95,339          90,061
                                                                   -----------     -----------
       Total current liabilities...............................      1,111,290       1,210,748
                                                                   -----------     -----------
DEFERRED CREDITS
Deferred income taxes (Note 7).................................        672,266         758,633
Accumulated deferred investment tax credits....................         31,031          33,229
Deferred credits and other liabilities (Note 7)................        266,077         179,756
                                                                   -----------     -----------
       Total deferred credits..................................        969,374         971,618
                                                                   -----------     -----------
COMMITMENTS AND CONTINGENCIES (Note 17)
                                                                   -----------     -----------
       Total stockholders' equity and liabilities..............    $ 5,418,293     $ 5,518,673
                                                                   ===========     ===========
 
----------------------------------------------------------------------------------------------
</TABLE>
 
                                       43
<PAGE>   46
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
                      CONSOLIDATED STATEMENT OF CASH FLOWS
 
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
For the Years Ended December 31,                                 1995          1994          1993
---------------------------------------------------------------------------------------------------
                                                                     (Thousands of Dollars)
<S>                                                           <C>           <C>           <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income................................................    $  21,344     $ 183,171     $ 205,916
Adjustments to reconcile net income to net cash
  provided by operating activities
    Cumulative effect of applying SFAS No. 109............           --            --       (17,422)
    Depreciation and amortization.........................      256,636       279,317       294,648
    Impairment of gas and oil producing properties........      226,209            --            --
    Write-down of coal properties.........................       31,266            --            --
    Deferred income taxes-net.............................      (48,767)      (60,744)      (19,782)
    Investment tax credit.................................       (2,198)       (2,567)       (2,620)
    Changes in current assets and current liabilities
       Accounts receivable-net............................     (116,529)       81,896      (107,292)
       Inventories........................................       77,024       (48,566)      (22,212)
       Unrecovered gas costs..............................      (11,988)        5,467       249,549
       Accounts payable...................................       69,761        11,198        13,831
       Estimated rate contingencies and refunds...........      (24,041)       25,948       (21,930)
       Amounts payable to customers.......................      (55,825)       68,538        24,393
       Taxes accrued......................................       19,922       (17,685)       16,909
       Other-net..........................................       13,643        (2,901)       (5,022)
    Changes in other assets and other liabilities.........       92,553       108,219      (137,571)
    Other-net.............................................        3,714            37          (446)
                                                              ---------     ---------     ---------
       Net cash provided by operating activities..........      552,724       631,328       470,949
                                                              ---------     ---------     ---------
CASH FLOWS USED IN INVESTING ACTIVITIES
Plant construction and other property additions...........     (434,739)     (416,051)     (333,056)
Proceeds from dispositions of property,
  plant and equipment-net.................................       14,066           164         4,716
Cost of other investments-net.............................       (7,464)      (14,902)         (567)
                                                              ---------     ---------     ---------
       Net cash used in investing activities..............     (428,137)     (430,789)     (328,907)
                                                              ---------     ---------     ---------
CASH FLOWS PROVIDED BY (OR USED IN) FINANCING ACTIVITIES
Issuance of common stock..................................       19,058           279        13,066
Issuance of debentures....................................      148,899            --       295,098
Purchase of debentures....................................           --            --      (283,208)
Unsecured loan repayment..................................       (4,000)           --            --
Commercial paper repayments-net...........................     (103,399)      (15,601)       (5,015)
Dividends paid............................................     (180,782)     (180,415)     (178,125)
Other-net.................................................           (9)           (1)          (91)
                                                              ---------     ---------     ---------
       Net cash used in financing activities..............     (120,233)     (195,738)     (158,275)
                                                              ---------     ---------     ---------
       Net increase (or decrease) in cash and
         temporary cash investments.......................        4,354         4,801       (16,233)
CASH AND TEMPORARY CASH INVESTMENTS AT JANUARY 1..........       31,923        27,122        43,355
                                                              ---------     ---------     ---------
CASH AND TEMPORARY CASH INVESTMENTS AT DECEMBER 31........    $  36,277     $  31,923     $  27,122
                                                              =========     =========     =========
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for
  Interest (net of amounts capitalized)...................    $ 102,663     $  91,011     $  92,880
  Income taxes (net of refunds)...........................    $  58,949     $ 154,860     $ 109,998
Non-cash financing activities
  Conversion of 7 1/4% Convertible Subordinated
    Debentures............................................    $      --     $   3,795     $      --
 
---------------------------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
 
                                       44
<PAGE>   47
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Methods of allocating costs to accounting periods by the subsidiary companies
subject to federal or state accounting and rate regulation may differ from
methods generally applied by nonregulated companies. However, when the
accounting allocations prescribed by regulatory authorities are used for
ratemaking, the economic effects thereof determine the application of generally
accepted accounting principles. Significant accounting policies of Consolidated
Natural Gas Company (the Parent Company) and subsidiaries (the Company) within
this framework are summarized in this Note.
 
USE OF ESTIMATES
The consolidated financial statements reflect certain estimates and assumptions
made by management that affect the reported amounts of assets and liabilities,
the disclosure of contingent assets and liabilities at the date of the financial
statements, and the reported amounts of revenues and expenses for the periods
presented.
 
PRINCIPLES OF CONSOLIDATION
The Parent Company owns all of the capital stock of its subsidiaries. The
consolidated financial statements represent the accounts of the Company after
the elimination of intercompany transactions.
 
The subsidiary companies follow the equity method of accounting for investments
in partnerships and corporate joint ventures when the subsidiary is able to
influence the financial and operating policies of the investee. For all other
investments, the cost method is applied.
 
REVENUE RECOGNITION
Revenues from gas sales and transportation services are recognized in the same
period in which the related gas volumes are delivered to customers. The
subsidiaries bill and recognize sales revenues from residential and certain
commercial and industrial customers on the basis of scheduled meter readings. In
addition, revenues are recorded for estimated deliveries of gas to these
customers from the meter reading date to the end of the accounting period. For
wholesale and other commercial and industrial customers, revenues are based upon
actual deliveries of gas to the end of the period.
 
UNRECOVERED GAS COSTS
Where permitted by regulatory authorities, the subsidiaries defer the difference
between the cost of gas (including certain related costs) and the amount of such
costs included in current rates. The differences are accounted for as either
unrecovered gas costs or amounts payable to customers. Unrecovered amounts are
recognized as purchased gas costs in future periods when the costs are recovered
through adjusted rates.
 
ENERGY PRICE RISK MANAGEMENT ACTIVITIES
Statement of Financial Accounting Standards (SFAS) No. 119, "Disclosure about
Derivative Financial Instruments and Fair Value of Financial Instruments,"
requires certain disclosures about derivative financial instruments but does not
affect the accounting for derivatives.
 
In the normal course of business, the nonregulated subsidiaries utilize
exchange-traded commodity futures and option contracts and derivative financial
instruments to manage exposure to price risk in connection with the production,
purchase and sale of natural gas and oil, and for stored gas inventories.
Derivative financial instruments may also be used from time to time to manage
foreign currency risk in connection with certain contractual commitments.
Exchange-traded instruments permit settlement by physical delivery of the
commodity under contract and are not considered derivative financial instruments
under SFAS No. 119. The derivative financial instruments utilized by the
subsidiaries include over-the-counter (OTC) commodity price swap agreements, OTC
foreign currency swap agreements and OTC options and require settlement in cash.
Under the price swap agreements, the subsidiaries make
 
                                       45
<PAGE>   48
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

payments to, or receive payments from, counterparties generally based on the
difference between fixed and variable gas prices or on prices at different
receipt points as specified in the contracts. Under foreign currency swap
agreements, payments are made to, or received from, counterparties generally
based on the difference in the current foreign exchange rate. Settlement takes
place under the swap agreements on a monthly basis, and amounts received or paid
are recognized as an adjustment to gas sales revenues, purchased gas expense or
transport capacity costs in that month to correspond with the recognition of the
related physical transaction.
 
For derivative financial instruments or exchange-traded contracts that qualify
(based on correlation to price movements of gas and oil) and are designated as
hedges, related gains or losses are deferred and subsequently recognized in
income, as gas sales revenues or purchased gas expense, in the same period the
hedged transaction occurs. Due to the nature of its operations, CNG Energy
Services marks-to-market the value of futures contracts related to stored gas
inventories each period, with gains and losses recognized in the operating
income of that period.
 
Margin accounts for open futures contracts are recorded in the Consolidated
Balance Sheet under "Prepayments and other current assets." Deferred losses or
gains are reflected in the Consolidated Balance Sheet under "Deferred charges
and other assets" and "Deferred credits and other liabilities," respectively.
Cash flows from price risk management activities are reported in the
Consolidated Statement of Cash Flows as an operating activity--consistent with
the category of the cash flows from the underlying physical transaction.
 
PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION
       GAS UTILITY AND OTHER PLANT
The property, plant and equipment accounts are stated at the cost incurred or,
where required by regulatory authorities, "original cost." Additions and
betterments are charged to the property accounts at cost. Upon normal retirement
of a plant asset, its cost is charged to accumulated depreciation together with
costs of removal less salvage. The costs of maintenance, repairs and replacing
minor items are charged principally to expense as incurred.
 
       EXPLORATION AND PRODUCTION PROPERTIES
CNG Producing and CNG Transmission follow the full cost method of accounting for
gas and oil producing activities prescribed by the Securities and Exchange
Commission (SEC). Under the full cost method, all costs directly associated with
property acquisition, exploration, and development activities are capitalized,
with the principal limitation that such amounts not exceed the present value of
estimated future net revenues to be derived from the production of proved gas
and oil reserves. If net capitalized costs exceed the estimated value at the end
of any quarterly period, then a permanent write-down of the assets must be
recognized in that period.
 
The gas and oil producing activities of the distribution subsidiaries are
subject to cost-of-service rate regulation and are exempt from the accounting
methods prescribed by the SEC.
 
       DEPRECIATION AND AMORTIZATION
Depreciation and amortization are recorded over the estimated service lives of
plant assets by application of the straight-line method or, in the case of gas
and oil producing properties, the unit-of-production method.
 
Under the full cost method of accounting, amortization is also accrued on
estimated future costs to be incurred in developing proved gas and oil reserves,
and on estimated dismantlement and abandonment costs net of projected salvage
values. However, the costs of investments in unproved properties and major
development projects are excluded from amortization until it is determined
whether or not proved reserves are attributable to such properties.
 
                                       46
<PAGE>   49
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

       ACCOUNTING FOR IMPAIRMENTS
In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of." This standard requires that long-lived assets and
certain intangibles be reviewed for impairment when events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. If the aggregate estimated future cash flows to be derived from an
asset are less than its carrying amount, an impairment must be recognized. SFAS
No. 121 also requires the write-off of a regulatory asset if and when it is no
longer probable that future revenues will provide for the recovery of the
carrying value of the asset. SFAS No. 121 is effective for fiscal years
beginning after December 15, 1995, and the Company will adopt the standard
effective January 1, 1996. The adoption is not expected to have a material
effect on the Company's financial position, results of operations or cash flows.
 
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The subsidiaries subject to cost-of-service rate regulation capitalize the
estimated costs of funds used during the construction of major projects. Under
regulatory practices, those companies are permitted to include the costs
capitalized in rate base for rate-making purposes when the completed facilities
are placed in service. The remaining subsidiaries capitalize interest costs as
part of the cost of acquiring certain assets. Generally, interest is capitalized
on unproved properties and major construction and development projects on which
amortization is not yet being recognized.
 
In determining the allowance for funds used during construction, the following
ranges of rates reflect the pretax cost of borrowed funds used to finance
construction expenditures: 1993 - 3 1/4% to 8 7/8%; 1994 - 3 3/8% to 8 1/4% and
1995 - 5 3/4% to 8 3/8%. There were no equity funds capitalized in those years.
 
INCOME TAXES
The current provision for income taxes represents amounts paid or currently
payable. Investment tax credits which were required to be deferred by regulatory
authorities are being amortized as credits to income over the estimated service
lives of the related properties.
 
Effective January 1, 1993, the Company adopted the provisions of SFAS No. 109,
"Accounting for Income Taxes." The adoption of SFAS No. 109 changed the
Company's method of accounting for income taxes from the deferred method to an
asset and liability approach. The cumulative effect of this accounting change
increased 1993 net income by $17,422,000, or $.19 per share, resulting primarily
from the reduction in deferred income tax balances associated with nonregulated
activities.
 
PENSION AND OTHER BENEFIT PROGRAMS
       PENSION PROGRAM
The subsidiaries have qualified noncontributory defined benefit pension plans
covering all employees. Benefits payable under the plans are based primarily on
each employee's years of service, age and base salary during the five years
prior to retirement. Net pension costs are determined by an independent actuary,
and the plans are funded on an annual basis to the extent such funding is
deductible under federal income tax regulations. Plan assets consist primarily
of equity securities, fixed income securities and insurance contracts. The
pension program also includes the payment of supplemental pension benefits to
certain retirees depending on retirement dates, and the payment of benefits to
certain retired executives under company-sponsored nonqualified employee benefit
plans.
 
Effective July 1, 1995, the Company applied SFAS No. 87 to certain of its
nonqualified employee benefit plans. Benefit costs under these plans had
previously been expensed as paid and were not material. The application of SFAS
No. 87 to these plans did not have a material effect on the Company's financial
position, results of operations or cash flows.
 
                                       47
<PAGE>   50
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

       OTHER POSTRETIREMENT BENEFITS
In addition to pension plans, the subsidiaries sponsor defined benefit
postretirement plans covering both salaried and hourly employees and certain
dependents. The plans provide medical benefits as well as life insurance
coverage. These benefits are provided through insurance companies and other
providers with the annual cash outlays based on the claim experience of the
related plans.
 
Employees who retire on or after attaining age 55 and having rendered at least
15 years of service, or employees retiring on or after attaining age 65, are
eligible to receive benefits under the plans. The plans are both contributory
and noncontributory, depending on age, retirement date, the plan elected by the
employee, and whether the employee is covered under a collective bargaining
agreement. Most of the medical plans contain cost-sharing features such as
deductibles and coinsurance. For certain of the contributory medical plans,
retiree contributions are adjusted annually.
 
       ACCOUNTING FOR STOCK-BASED COMPENSATION
In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based
Compensation." This standard encourages a fair value based method of accounting
for employee stock options and similar equity instruments. Although adoption of
this new method of accounting is optional, the standard requires companies
electing to follow existing accounting rules to disclose in a note the pro forma
effects as if the fair value based method of accounting had been applied. The
Company does not anticipate changing its accounting method for stock-based
compensation. As required, the new disclosures under SFAS No. 123 will be
reflected in the 1996 consolidated financial statements.
 
ENVIRONMENTAL EXPENDITURES
Environmental-related expenditures associated with current operations are
generally expensed as incurred. Expenditures for the assessment and/or
remediation of environmental conditions related to past operations are charged
to expense or are deferred pending probable recovery in future rate-making
proceedings. In this connection, a liability is recognized when the assessment
or remediation effort is probable and the future costs are estimable. Estimated
future costs for the abandonment and restoration of gas and oil properties are
accrued currently through charges to depreciation.
 
Claims for recovery of environmental-related costs from insurance carriers and
other third parties or through regulatory procedures are recognized separately
as assets when future recovery is deemed probable.
 
GAINS AND LOSSES ON REACQUISITION OF DEBT
Gains and losses (including redemption premiums) on the purchase or redemption
of the Company's debentures are generally deferred and then included in income
over the original lives of the applicable debenture issues to give recognition
to the economic effect of the rate-making process on certain subsidiaries. The
portion not deferred is recognized in the period of the transaction.
 
EARNINGS PER SHARE
Earnings per share of common stock is computed based on the weighted average
number of common shares outstanding during the period. Under the methods
prescribed by generally accepted accounting principles, the assumed exercise of
outstanding stock options is not considered to have a dilutive effect on
earnings per share. Also, the conversion of the Company's outstanding
convertible subordinated debentures has not been assumed in determining earnings
per share since such conversion would be antidilutive.
 
                                       48
<PAGE>   51
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

TEMPORARY CASH INVESTMENTS
Temporary cash investments consist of short-term, highly liquid investments that
are readily convertible to cash and present no significant interest rate risk.
For purposes of the Consolidated Statement of Cash Flows, temporary cash
investments are considered to be cash equivalents.
 
2.     RATE MATTERS
Certain increases in prices by subsidiaries and other rate-making issues are
subject to final modification in regulatory proceedings. The related accumulated
provisions pertaining to these matters were $52,210,000 and $24,239,000 at
December 31, 1994 and 1995, including interest. These amounts are reported in
the Consolidated Balance Sheet under "Estimated rate contingencies and refunds"
together with $31,194,000 and $35,124,000, respectively, which are primarily
refunds received from suppliers and refundable to customers under regulatory
procedures.
 
As approved by the Federal Energy Regulatory Commission (FERC), CNG Transmission
has billed its customers, including certain affiliates, a total of $178.6
million, representing unrecovered purchased gas costs and unrecovered
sales-related transportation costs, resulting from its transition to
restructured services under FERC Order 636. Of the total amount billed by CNG
Transmission to the distribution subsidiaries, $21,070,000 is included in the
Consolidated Balance Sheet at December 31, 1995, under "Deferred charges and
other assets," representing remaining amounts to be recovered from their
customers.
 
The distribution subsidiaries have incurred or are expected to incur obligations
to upstream pipeline companies, including CNG Transmission, for transition costs
under FERC Order 636. The total estimated liability for such costs was
$69,451,000 and $37,021,000 at December 31, 1994 and 1995, respectively.
Additional amounts are likely to be accrued in the future once the pipeline
companies receive final FERC approval to recover these costs. Based on
management's current estimates, the distribution subsidiaries' portion of such
costs could be in the range of $25 million.
 
Based on regulatory actions in two jurisdictions and the past rate-making
treatment of similar costs in the other jurisdictions, management believes that
the distribution subsidiaries should generally be able to pass through all Order
636 transition costs to their customers.
 
3.     PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION
IMPAIRMENT OF GAS AND OIL PRODUCING PROPERTIES
As described in Note 1, certain of the subsidiaries follow the full cost method
of accounting for gas and oil producing activities as prescribed by the SEC.
Under these rules, the Company recognized an impairment of its gas and oil
producing properties at March 31, 1995, due primarily to the decline in gas
wellhead prices. The non-cash charge amounted to $226,209,000 and reduced 1995
first quarter net income by $145,000,000, or $1.56 per share.
 
DEPRECIATION AND AMORTIZATION
Amortization of capitalized costs under the full cost method of accounting for
the Company's exploration and production operations amounted to $1.18 per
thousand cubic feet (Mcf) equivalent of gas and oil produced in 1993, $1.15 in
1994, and $.98 in 1995. The 1995 amount includes the effect of the write-down of
the gas and oil producing properties noted above.
 
                                       49
<PAGE>   52
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Costs of unproved properties capitalized under the full cost method of
accounting that are excluded from amortization at December 31, 1995, and the
years in which such excluded costs were incurred, follow:
 
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
                                                        Incurred in Years Ended December 31,
                                      DECEMBER 31,     ---------------------------------------
                                          1995          1995       1994       1993      Prior
----------------------------------------------------------------------------------------------
                                                          (In Thousands)
<S>                                          <C>       <C>        <C>        <C>       <C>
Property acquisition costs...........        $15,237   $ 5,521    $ 4,855    $3,143    $ 1,718
Exploration costs....................         27,625    10,459      4,949     1,986     10,231
Capitalized interest.................          5,396       753      1,401     1,054      2,188
                                             -------   -------    -------    ------    -------
     Total...........................        $48,258   $16,733    $11,205    $6,183    $14,137
                                             =======   =======    =======    ======    =======
----------------------------------------------------------------------------------------------
</TABLE>
 
There are no significant properties, as defined by the SEC, excluded from
amortization at December 31, 1995. As gas and oil reserves are proved through
drilling or as properties are judged to be impaired, excluded costs and any
related reserves are transferred on an ongoing, well-by-well basis into the
amortization calculation.
 
WRITE-DOWN OF COAL PROPERTIES
In connection with a review of non-strategic assets, the Company initiated an
evaluation during 1995 of the possible disposition of the coal reserves and
related properties owned by CNG Coal. These reserves had been acquired in the
late 1960s and 1970s to meet expected long-term gas supply needs through coal
gasification. However, due to gas industry deregulation, excess gas supplies
nationwide, and both low demand and prices for coal, the Company concluded that
it was not economically feasible to develop such reserves at this time, nor were
these assets currently aligned with the Company's longer-term strategy.
 
An appraisal of the properties was completed during the second quarter of 1995
by an independent geological firm, which indicated that a write-down was
warranted. Accordingly, at June 30, 1995, the cost of these properties was
written down resulting in a pretax charge amounting to $31,266,000. This charge
reduced 1995 second quarter net income by $20,323,000, or 22 cents per share,
but had no effect on the Company's cash flow. In the fourth quarter of 1995, the
Company entered into a non-binding letter of intent for the proposed sale of
these properties to a third party. Negotiations are in progress with the third
party to finalize the sale. Any gain or loss resulting from the disposition of
these properties is not expected to be material.
 
4.     WORKFORCE REDUCTION COSTS
In March 1995, the Board of Directors approved a workforce reduction program as
part of the Company's efforts to permanently reduce costs in response to
competitive conditions. The workforce reduction program consisted of a voluntary
early retirement program, with eligibility based upon the employee's age and
years of service as of December 31, 1995, and an involuntary separation program.
The early retirement incentives included five additional years of age and
pension service for determining pension benefits. The early retirement program
was offered at six of the subsidiaries from April 1 through May 31, 1995, with
eligible employees retiring before December 31, 1995. The involuntary separation
program involved severance benefit payments to affected employees. In June 1995,
the Board of Directors approved a separate workforce reduction program at a
seventh subsidiary that included voluntary early retirement incentives and
severance benefits similar to those offered at the other six subsidiaries. The
early retirement program was offered at the seventh subsidiary from July 1
through August 31, 1995. Eligible employees under this program also retired
before December 31, 1995.
 
                                       50
<PAGE>   53
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

A total of 571 eligible employees elected to accept the early retirement offer
and an additional 217 employees were separated from the Company in conjunction
with these programs. Accordingly, the Company recorded charges to "Operation
expense" in the 1995 Consolidated Statement of Income amounting to $42,555,000.
These charges reduced 1995 net income by $25,618,000, or 27 cents per share. In
addition, certain of the regulated subsidiaries have deferred, as a regulatory
asset, a portion of their workforce reduction costs pending recovery in future
rates. The balance of these deferrals was $16,379,000 at December 31, 1995. The
total workforce reduction costs include the impact of curtailment accounting for
the pension and postretirement benefit plans. Details of the costs are shown in
the following table.
 
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------
                                                  Amounts           Amounts
                                                  Expensed        Deferred at         Total
                                                  in 1995      December 31, 1995      Costs
--------------------------------------------------------------------------------------------
                                                                (In Thousands)
<S>                                               <C>          <C>                   <C>
Pension and nonqualified benefit plans:
  Special termination benefit cost.............   $30,284           $ 6,893          $37,177
  Curtailment gain-net.........................    (5,891)             (277)          (6,168)
Postretirement benefit plans:
  Special termination benefit cost.............     1,086                62            1,148
  Curtailment loss-net.........................     6,008             9,656           15,664
Severance and other............................    11,068                45           11,113
                                                  -------           -------          -------
  Total........................................   $42,555           $16,379          $58,934
                                                  =======           =======          =======
--------------------------------------------------------------------------------------------
</TABLE>
 
In January 1996, unions at two subsidiaries approved the adoption of an early
retirement program with voluntary early retirement incentives similar to those
described above. The early retirement program will be offered to eligible union
employees from February 1 through March 31, 1996, with most retirement dates
effective April 1, 1996. Costs resulting from the program will be recognized in
1996, but are not expected to be material.
 
5.     PENSION COSTS
Net pension cost, as determined by an independent actuary, included the
following components:
 
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------
Years Ended December 31,                                    1995          1994         1993
---------------------------------------------------------------------------------------------
                                                                     (In Thousands)
<S>                                                       <C>           <C>          <C>
Service cost - benefits earned during the period.......   $  23,741     $ 28,509     $ 27,266
Interest cost on projected benefit obligation..........      62,125       59,006       56,834
Return on plan assets..................................    (265,460)     (33,363)     (89,441)
Net amortization and deferral..........................     162,002      (60,228)        (303)
Curtailment and special termination benefits...........      24,393           --           --
Special voluntary retirement programs..................         800          800          800
                                                          ---------     --------     --------
  Net pension cost (or credit).........................   $   7,601     $ (5,276)    $ (4,844)
                                                          =========     ========     ========
---------------------------------------------------------------------------------------------
</TABLE>
 
In 1989, Peoples Natural Gas offered special retirement incentives to certain
salaried and hourly employees. The additional pension payments resulting from
these incentives are being paid from the assets of the applicable pension plans.
The estimated cost of these additional benefits, amounting to approximately
$8,000,000, was deferred and is being amortized to expense over a 10-year period
which
 
                                       51
<PAGE>   54
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

began October 1, 1990, in accordance with the rate-making treatment approved by
the Pennsylvania Public Utility Commission.
 
The following table sets forth the funded status of the plans, as determined by
an independent actuary, at December 31, 1994 and 1995:
 
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------
                                                          
                                                         
                                                    Plans Where Assets           Plans Where
                                                    Exceed Accumulated      Accumulated Benefits
                                                         Benefits               Exceed Assets
                                                ------------------------    --------------------
                December 31,                       1995          1994         1995        1994
------------------------------------------------------------------------------------------------
                                                                 (In Thousands)
<S>                                             <C>           <C>           <C>         <C>
Actuarial present value of:
  Vested benefit obligation..................   $  711,644    $  600,111    $ 25,203    $ 13,717
                                                ==========    ==========    ========    ========
  Accumulated benefit obligation.............   $  740,890    $  625,900    $ 28,858    $ 13,717
                                                ==========    ==========    ========    ========
  Projected benefit obligation...............   $  952,260    $  832,431    $ 36,044    $ 13,717
Plan assets at fair value....................    1,395,778     1,178,505          --          --
                                                ----------    ----------    --------    --------
  Plan assets in excess of (or less than)
     projected benefit obligation............      443,518       346,074     (36,044)    (13,717)
Unrecognized net loss (or gain)..............     (354,370)     (242,721)      1,358       1,901
Unrecognized net obligation (or asset).......      (77,300)      (86,620)     21,396       1,970
Unrecognized prior service cost..............        5,634         7,053       2,341       3,067
Recognition of minimum liability.............           --            --     (17,909)     (6,938)
                                                ----------    ----------    --------    --------
  Prepaid pension cost (or pension
     liability)..............................   $   17,482    $   23,786    $(28,858)   $(13,717)
                                                ==========    ==========    ========    ========
------------------------------------------------------------------------------------------------
</TABLE>
 
The projected benefit obligation at December 31, 1994 and 1995, was determined
using an annual discount rate of 7.5% and 7.0%, respectively, and an average
assumed annual rate of salary increase of 5.5%. The expected long-term rate of
return on plan assets was 8.0% per annum.
 
The minimum liability and related intangible asset recognized relating to the
Company's supplemental pension benefit plans at December 31, 1994, was
$6,938,000 and $5,037,000, respectively. As described in Note 1, the Company
applied the provisions of SFAS No. 87 to certain nonqualified employee benefit
plans effective July 1, 1995. The minimum liability and related intangible asset
recognized relating to both the supplemental pension and nonqualified employee
benefit plans at December 31, 1995, was $17,909,000 and $15,605,000,
respectively. These amounts are included in the Consolidated Balance Sheet under
"Deferred credits and other liabilities" and "Deferred charges and other
assets." Adjustments of the minimum liability and intangible asset due to
changes in assumptions or the financial status of the plans resulted in a credit
to retained earnings of $386,000 at December 31, 1994, and a charge to retained
earnings of $262,000 at December 31, 1995.
 
                                       52
<PAGE>   55
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6.     OTHER POSTRETIREMENT BENEFITS
Net periodic postretirement benefit cost, as determined by an independent
actuary, included the following components:
 
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------
Years Ended December 31,                                         1995       1994       1993
---------------------------------------------------------------------------------------------
                                                                       (In Thousands)
<S>                                                             <C>        <C>        <C>
Service cost - benefits attributed to service during the
  period.....................................................   $11,549    $12,708    $10,549
Interest cost on accumulated postretirement benefit
  obligation.................................................    28,017     24,380     23,208
Return on plan assets........................................      (145)       (28)        --
Amortization of transition obligation........................    14,420     14,420     14,420
Curtailment and special termination benefits.................     7,094         --         --
Net amortization and deferral................................       380          4         --
                                                                -------    -------    -------
  Net periodic postretirement benefit cost...................   $61,315    $51,484    $48,177
                                                                =======    =======    =======
---------------------------------------------------------------------------------------------
</TABLE>
 
The following table reconciles the plans' combined funded status, as determined
by an independent actuary, with amounts included in the Consolidated Balance
Sheet at December 31, 1994 and 1995:
 
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------
December 31,                                                           1995          1994
--------------------------------------------------------------------------------------------
                                                                         (In Thousands)
<S>                                                                  <C>           <C>
Accumulated postretirement benefit obligation:
  Retirees........................................................   $ 271,209     $ 208,685
  Fully eligible active plan participants.........................      25,475        41,433
  Other active plan participants..................................      88,235        85,757
                                                                     ---------     ---------
     Total accumulated postretirement benefit obligation..........     384,919       335,875
Plan assets at fair value.........................................      12,127         2,717
                                                                     ---------     ---------
     Accumulated postretirement benefit obligation in
       excess of plan assets......................................    (372,792)     (333,158)
Unrecognized prior service cost...................................     (20,887)       (6,930)
Unrecognized net loss.............................................      64,166        21,113
Unrecognized transition obligation................................     230,853       259,553
                                                                     ---------     ---------
     Accrued postretirement benefit liability.....................   $ (98,660)    $ (59,422)
                                                                     =========     =========
--------------------------------------------------------------------------------------------
</TABLE>
 
As permitted, the Company elected to amortize the accumulated postretirement
benefit obligation existing at January 1, 1993 (transition obligation) of
$288,393,000 over a 20-year period. The weighted average discount rate used in
determining the accumulated postretirement benefit obligation at December 31,
1994 and 1995, was 8.25% and 7.00%, respectively. The average assumed annual
rate of salary increase for the applicable life insurance plans was 5.5% in 1994
and 5.0% in 1995.
 
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation for the medical plans is 8.5% for 1996,
declining gradually to 5.0% in 2003 and remaining at that level thereafter. The
health care cost trend rate assumption has a significant effect on the amounts
reported. If the health care cost trend rate were increased by 1% in each year,
the accumulated postretirement benefit obligation as of December 31, 1995, would
be increased by $42.1 million. A 1% change would also increase the aggregate of
the service and interest cost components of net periodic postretirement benefit
cost for 1995 by $5.2 million.
 
The majority of the estimated postretirement benefit costs and the transition
obligation is attributable to the rate-regulated subsidiaries. Pending the
expected recovery of SFAS No. 106 costs and related
 
                                       53
<PAGE>   56
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

deferrals in regulatory proceedings, these subsidiaries have generally deferred
the differences between SFAS No. 106 costs and amounts included in rates. In
general, the rate-regulated subsidiaries have obtained approval for recovery in
rates from their respective regulatory commissions for the increased level of
expense resulting from the adoption of SFAS No. 106. The amount of SFAS No. 106
costs deferred at December 31, 1994 and 1995, was $55,185,000 and $68,026,000,
respectively, which is included in the Consolidated Balance Sheet under
"Deferred charges and other assets."
 
The FERC and certain state regulatory authorities have indicated that when SFAS
No. 106 costs are recovered in rates, amounts collected must be deposited in
irrevocable trust funds dedicated for the sole purpose of paying postretirement
benefits. Accordingly, two subsidiaries began funding postretirement benefit
costs via voluntary employees' beneficiary associations (VEBAs) during 1994 and
one subsidiary began funding in 1995. A fourth subsidiary is expected to begin
funding in 1996. The remaining subsidiaries do not prefund postretirement
benefit costs, but rather pay claims as presented. Assets held by the VEBAs
consist primarily of short-term fixed income securities.
 
7.     INCOME TAXES
As described in Note 1, the Company adopted the provisions of SFAS No. 109
effective January 1, 1993. The cumulative effect of this accounting change
increased 1993 net income by $17,422,000, or $.19 per share, due primarily to
the reduction in deferred tax balances associated with nonregulated activities.
 
"Income taxes" in the Consolidated Statement of Income include the following:
 
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------
Years Ended December 31,                                     1995         1994         1993
---------------------------------------------------------------------------------------------
                                                                     (In Thousands)
<S>                                                        <C>          <C>          <C>
Current provision
  Federal...............................................   $ 44,705     $126,362     $ 99,029
  State.................................................      9,203       19,376       23,279
Deferred income taxes-net
  Federal...............................................    (47,146)     (50,443)      (6,688)
  State.................................................     (1,621)     (10,301)     (13,094)
Investment tax credit...................................     (2,198)      (2,567)      (2,620)
                                                           --------     --------     --------
  Total.................................................   $  2,943     $ 82,427     $ 99,906
                                                           ========     ========     ========
---------------------------------------------------------------------------------------------
</TABLE>
 
In August 1993, the federal corporate income tax rate was increased from 34% to
35%, retroactive to January 1, 1993. As required by Statement No. 109, existing
deferred tax assets and liabilities were adjusted to reflect this enacted tax
rate change. As a result, deferred income tax expense in 1993 was increased by
$11,429,000, or $.12 per share.
 
Income taxes differed from the amounts shown in the next table that were
computed by applying the statutory federal income tax rate of 35% to reported
income before taxes. The reasons for the differences follow:
 
                                       54
<PAGE>   57
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------
Years Ended December 31,                                     1995         1994         1993
---------------------------------------------------------------------------------------------
                                                                     (In Thousands)
<S>                                                         <C>         <C>          <C>
Income before taxes......................................   $24,287     $265,598     $288,400
                                                            =======     ========     ========
Computed "expected" tax expense..........................   $ 8,500     $ 92,959     $100,940
Increases (or reductions) in tax resulting from:
  Production tax credit..................................    (8,472)      (7,987)      (8,435)
  Investment tax credit..................................    (2,198)      (2,567)      (2,620)
  State income taxes.....................................     4,928        5,899        6,620
  Effect of increase in federal corporate income tax rate
     on deferred income taxes............................        --           --       11,429
  Miscellaneous..........................................       185       (5,877)      (8,028)
                                                            -------     --------     --------
       Total income taxes................................   $ 2,943     $ 82,427     $ 99,906
                                                            =======     ========     ========
  Effective tax rate.....................................     12.1%        31.0%        34.6%
---------------------------------------------------------------------------------------------
</TABLE>
 
The current and noncurrent deferred income taxes reported in the Consolidated
Balance Sheet at December 31, 1995, represent the net expected future tax
consequences attributable to temporary differences between the carrying amounts
of nontax assets and liabilities and their tax bases. These temporary
differences and the related tax effect were as follows:
 
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
                                                                         1995
                                                         -------------------------------------
                                                         Deferred income      Deferred income
December 31,                                                  taxes           taxes - current
----------------------------------------------------------------------------------------------
<S>                                                      <C>                  <C>
                                                                    (In Thousands)
Deferred tax liabilities:
  Excess of tax over book depreciation................       $497,415             $     --
  Exploration and intangible well drilling costs......        217,352                   --
  FERC Order 636 transition costs.....................          7,838                   --
  Unrecovered gas costs...............................             --                9,232
  Other...............................................         68,751                   --
                                                               ------             --------
     Total liabilities................................        791,356                9,232
                                                               ------             --------
Deferred tax assets:
  Tax basis step-up in connection with acquisition of
     subsidiary.......................................         19,923                   --
  Deferred investment tax credits.....................         18,817                   --
  Overheads capitalized for tax purposes..............         11,092                   --
  Write-down of coal properties.......................         10,943                   --
  Amounts payable to customers........................             --               14,710
  Supplier and other refunds..........................             --                5,338
  Other...............................................         58,315               10,177
  Valuation allowance.................................             --                   --
                                                               ------             --------
     Total assets.....................................        119,090               30,225
                                                               ------             --------
     Total deferred income taxes......................       $672,266             $(20,993)
                                                             ========             ========
----------------------------------------------------------------------------------------------
</TABLE>
 
                                       55
<PAGE>   58
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

A regulatory liability amounting to $61,678,000 has been recorded representing
the reduction to previously recorded deferred income taxes associated with
rate-regulated activities that are expected to be refundable to customers, net
of certain taxes collectible from customers. Also, a regulatory asset
corresponding to the recognition of additional deferred income taxes not
previously recorded because of past rate-making practices amounting to
$105,159,000 has been recorded at December 31, 1995. These amounts are included
in the Consolidated Balance Sheet under "Deferred credits and other liabilities"
and "Deferred charges and other assets," respectively.
 
8.     GAS STORED
The distribution subsidiaries, except Virginia Natural Gas, value their stored
gas inventory under the LIFO method. Virginia Natural Gas and CNG Energy
Services value their stored gas inventory under the weighted average cost
method. Based upon the average price of gas purchased during 1995, the current
cost of replacing the inventory of "Gas stored--current portion" exceeded the
amount stated on a LIFO basis by approximately $152,938,000 at December 31,
1995.
 
A portion of gas in underground storage used as a pressure base and for
operational balancing is included in "Property, Plant and Equipment" in the
amounts of $126,496,000 and $126,393,000 at December 31, 1994 and 1995,
respectively.
 
9.     UNAMORTIZED ABANDONED FACILITIES
In 1988, Consolidated LNG received FERC approval for the abandonment of its
interest in liquefied natural gas facilities at Cove Point, Maryland. In
connection with the abandonment, Consolidated LNG recorded a deferred asset in
accordance with the provisions of SFAS No. 90, "Accounting for Abandonments and
Disallowances of Plant Costs." This deferred asset, which represents the present
value of allowable costs expected to be recovered, is being amortized over the
10-year recovery period which began March 1, 1988, as prescribed in the FERC
order.
 
                                       56
<PAGE>   59
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. COMMON STOCKHOLDERS' EQUITY
A summary of the changes in stockholders' equity follows:
 
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------
                               Common Stock
                                  Issued                   Capital in Excess                            Treasury Stock
                           ---------------------             of Par Value                            --------------------
                           Number of     Value      -------------------------------     Retained     Number of
                            Shares       at Par     Paid-In      Other      Total       Earnings      Shares       Cost
-------------------------------------------------------------------------------------------------------------------------
                                                                   (In Thousands)
<S>                        <C>          <C>         <C>         <C>        <C>         <C>           <C>          <C>
Balance at December 31,
  1992..................      92,557    $254,532    $398,749    $40,280    $439,029    $1,439,277           --    $    --
Net income..............          --          --          --         --          --       205,916           --         --
Cash dividends declared
  Common stock ($1.925
    per share)..........          --          --          --         --          --      (178,771)          --         --
Common stock issued
  Stock options.........         238         654       8,834         --       8,834            --           --         --
  Stock awards-net......          66         180       2,925         --       2,925            --           --         --
  DRP*..................          58         159       2,697         --       2,697            --           --         --
  System Thrift Plans...          15          43         679         --         679            --           --         --
Purchase of treasury
  stock.................          --          --          --         --          --            --          (29)    (1,417)
Sale of treasury
  stock.................          --          --         (83)        --         (83)           --           29      1,417
Pension liability
  adjustment............          --          --          --         --          --           361           --         --
                              ------    --------    --------    -------    --------    ----------          ---    -------
Balance at December 31,
  1993..................      92,934     255,568     413,801     40,280     454,081     1,466,783           --         --
Net income..............          --          --          --         --          --       183,171           --         --
Cash dividends declared
  Common stock ($1.94
    per share)..........          --          --          --         --          --      (180,461)          --         --
Common stock issued
  Conversion of
    debentures..........          70         193       3,669         --       3,669            --           --         --
  Stock awards-net......          16          45         621         --         621            --           --         --
  Stock options.........           8          21         258         --         258            --           --         --
Purchase of treasury
  stock.................          --          --          --         --          --            --           (6)      (257)
Sale of treasury
  stock.................          --          --          (1)        --          (1)           --            6        257
Pension liability
  adjustment (Note 5)...          --          --          --         --          --           386           --         --
                              ------    --------    --------    -------    --------    ----------          ---    -------
Balance at December 31,
  1994..................      93,028     255,827     418,348     40,280     458,628     1,469,879           --         --
Net income..............          --          --          --         --          --        21,344           --         --
Cash dividends declared
  Common stock ($1.94
    per share)..........          --          --          --         --          --      (181,055)          --         --
Common stock issued
  Stock options.........         217         596       7,453         --       7,453            --           --         --
  System Thrift Plans...         213         586       7,586         --       7,586            --           --         --
  DRP*..................         104         287       3,837         --       3,837            --           --         --
  Stock awards-net......          30          81       1,040         --       1,040            --           --         --
Purchase of treasury
  stock.................          --          --          --         --          --            --          (17)      (634)
Sale of treasury
  stock.................          --          --          (9)        --          (9)           --           17        634
Pension liability
  adjustment (Note 5)...          --          --          --         --          --          (262)          --         --
                              ------    --------    --------    -------    --------    ----------          ---    -------
Balance at December 31,
  1995..................      93,592    $257,377    $438,255    $40,280    $478,535    $1,309,906           --    $    --
                              ======    ========    ========    =======    ========    ==========          ===    =======
-------------------------------------------------------------------------------------------------------------------------
<FN>
 
* Dividend Reinvestment Plan.
</TABLE>
 
                                       57
<PAGE>   60
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

SHAREHOLDER RIGHTS PLAN
On November 13, 1995, the Board of Directors adopted a shareholder rights plan
and on January 23, 1996, declared a dividend of one right (Right) for each share
of common stock outstanding at the close of business on February 28, 1996. Each
Right would entitle the holder to purchase from the Company one-half of one
share of common stock at a price of $175 per share ($87.50 per half-share),
subject to adjustment (Purchase Price), if certain conditions are met in
connection with a possible acquisition of the common stock of the Company by a
third party. If the Rights become exercisable, each holder may exercise a Right
and receive common stock (or, in certain cases, cash, property or other
securities) of the Company or common stock of the acquiring company having a
value equal to twice the Right's then current Purchase Price.
 
Also, under certain conditions, the Board of Directors may exchange the Rights,
in whole or in part, at an exchange ratio of one share of common stock (and/or
other securities, cash or other assets having the same value as a share of
common stock) per Right, subject to adjustment, or may redeem the Rights in
whole at a price of $0.01 per Right. Until a Right is exercised or exchanged for
common stock, the holder, as such, is not a stockholder of the Company. Unless
earlier exercised or redeemed, the Rights will expire on February 28, 2006.
 
UNISSUED SHARES
At December 31, 1995, 106,408,377 shares of common stock were unissued. Of
these, a total of 16,326,310 shares have been registered with the SEC for
possible issuance under various benefit plans. Shares acquired by these plans
can consist of original issue shares, treasury shares or shares purchased in the
open market. In addition, 2,098,824 shares have been registered with the SEC for
possible issuance to shareholders under the Dividend Reinvestment Plan and
4,559,353 shares are registered for issuance upon conversion of the Company's
convertible subordinated debentures.
 
TREASURY STOCK
Under a stock repurchase plan approved by the Board of Directors, the Company
can purchase in the open market up to 4,000,000 shares of its common stock. The
Company may also acquire shares of its common stock through certain provisions
of the 1991 Stock Incentive Plan and the Long-Term Incentive Plan. Shares
repurchased or acquired are held as treasury stock and are available for
reissuance for general corporate purposes or in connection with various employee
benefit plans. When treasury shares are reissued, the difference between the
market value at reissuance and the cost of shares is reflected in "Capital in
excess of par value." The cost of any shares held as treasury stock is shown as
a reduction in common stockholders' equity in the Consolidated Balance Sheet. No
treasury shares were held at December 31, 1994 or 1995.
 
STOCK AWARDS AND STOCK OPTIONS
       1991 STOCK INCENTIVE PLAN
The 1991 Stock Incentive Plan provides for the granting of stock awards, stock
options and other stock-based awards to employees of the Company. The maximum
number of shares available for issuance in each calendar year is determined in
accordance with a formula contained in the plan. During 1995, 3,741,422 shares
were available for issuance under the plan.
 
Stock awards granted under the plan may be in the form of restricted stock or
deferred stock. Shares issued as restricted stock awards are held by the Company
until the attached restrictions lapse. Deferred stock awards generally consist
of a right to receive shares at the end of specified deferral periods. The
market value of the stock award on the date granted is recorded as compensation
expense over the applicable restriction or deferral period.
 
                                       58
<PAGE>   61
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Stock options granted under the plan allow the purchase of common shares at a
price not less than fair market value at the date of grant and not less than par
value. The options generally are exercisable in four equal annual installments
commencing with the second anniversary of the grant and expire after 10 years
from the date of grant.
 
Stock appreciation rights may also be granted, either alone or in tandem with
stock options. These rights permit the recipient to receive, upon exercise, the
excess of the fair market value of a share on the date of exercise over the
grant price. The grant price is generally the fair market value of the stock on
the date of grant. As of December 31, 1995, no stock appreciation rights have
been granted under the plan.
 
The 1991 Stock Incentive Plan also provides for the granting of performance
awards, dividend equivalents, or other awards which may be based on, or related
to, shares of the Company's common stock. The granting of stock awards
constitutes a non-cash financing activity of the Company.
 
       1995 EMPLOYEE STOCK INCENTIVE PLAN
The 1995 Employee Stock Incentive Plan was established in conjunction with the
Long-Term Strategic Incentive Program described below. This plan provides for
the granting of stock-based awards to certain key employees similar to those
granted under the 1991 Stock Incentive Plan. There were no grants made under
this plan during 1995.
 
       LONG-TERM INCENTIVE PLAN
The Long-Term Incentive Plan, which provided for the issuance of common shares
to key employees as either restricted stock awards or stock options, terminated
by its terms on November 9, 1991. However, the provisions of the plan continue
with respect to any restricted stock awards and stock options granted prior to
the termination date. The terms and conditions of the options granted under this
plan are similar to those under the 1991 Stock Incentive Plan.
 
A summary of stock option activity under both the 1991 Stock Incentive Plan and
the Long-Term Incentive Plan for the years ended December 31, 1993 through 1995,
follows:
 
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------
                                                                 Number        Option Price
                                                               of Shares         Per Share
--------------------------------------------------------------------------------------------
<S>                                                          <C>               <C>
                                                             (In Thousands)
Shares under option:
  At January 1, 1993......................................        1,713        $32.50--$50.75
  Granted.................................................          552        $44.88--$55.00
  Exercised...............................................         (238)       $33.25--$50.75
  Cancelled...............................................          (65)       $34.75--$50.75
                                                                -------
  At December 31, 1993....................................        1,962        $32.50--$55.00
  Granted.................................................          651        $34.75--$45.13
  Exercised...............................................           (8)       $34.38--$43.88
  Cancelled...............................................          (48)       $34.75--$50.75
                                                                -------
  At December 31, 1994....................................        2,557        $32.50--$55.00
  Granted.................................................        1,078        $37.25--$45.38
  Exercised...............................................         (217)       $34.38--$43.88
  Cancelled...............................................         (470)       $34.38--$55.00
                                                                -------
  At December 31, 1995....................................        2,948        $32.50--$55.00
                                                                =======
--------------------------------------------------------------------------------------------
</TABLE>
 
                                       59
<PAGE>   62
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Effective January 2, 1996, additional options for the purchase of 482,500 shares
were granted to eligible employees. At December 31, 1995, options were
exercisable for the purchase of 1,048,064 shares. Stock options become
exercisable for the purchase of 401,776 shares in 1996, 534,731 in 1997, 424,323
in 1998, and 539,076 shares thereafter.
 
       LONG-TERM STRATEGIC INCENTIVE PROGRAM
On December 12, 1995, the Board of Directors approved the Long-Term Strategic
Incentive Program. Grants under this program, consisting of performance
restricted stock awards (performance shares) and nonqualified stock options, are
expected to be made every three years. Performance shares will vest contingent
upon attainment of certain strategic business results over a three-year period.
Stock options granted under this program vest after three years and will be
exercisable for one day. The exercise period can be extended from the vesting
date up to 10 years for all or a portion of the options if certain strategic
business results are attained over the vesting period. Awards under this program
will utilize shares available under both the 1991 Stock Incentive Plan and the
1995 Employee Stock Incentive Plan. No awards were made under this program in
1995. Effective January 2, 1996, grants were made under the program consisting
of 331,700 performance shares and 2,624,000 stock options.
 
11.     PREFERRED STOCK
The Company's authorized cumulative preferred stock consists of 2,500,000 shares
at a par value of $100 each. There were no shares of preferred stock issued or
outstanding at December 31, 1994 or 1995.
 
12.     DIVIDEND RESTRICTIONS
The indenture relating to the Company's senior debenture issues and the
preferred stock provisions of its Certificate of Incorporation contain
restrictions on dividend payments by the Company and acquisitions of its capital
stock. Under the indenture provisions (there being no preferred stock
outstanding), $506,988,000 of consolidated retained earnings was free from such
restrictions at December 31, 1995. The indenture also imposes dividend
limitations on the subsidiaries, but at December 31, 1995, these limitations did
not restrict their ability to pay dividends to the Company.
 
                                       60
<PAGE>   63
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13.     LONG-TERM DEBT
Long-term debt, excluding current maturities, follows:
 
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------
December 31,                                                          1995            1994
---------------------------------------------------------------------------------------------
                                                                         (In Thousands)
<S>                                                                <C>             <C>
Debentures
  7 3/8%, Due April 1, 2005...................................     $  150,000      $       --
  6 5/8%, Due December 1, 2013................................        150,000         150,000
  5 3/4%, Due August 1, 2003..................................        150,000         150,000
  5 7/8%, Due October 1, 1998.................................        150,000         150,000
  8 3/4%, Due October 1, 2019.................................        150,000         150,000
  8 3/4%, Due June 1, 1999....................................        100,000         100,000
  9 3/8%, Due February 1, 1997................................        100,000         100,000
  8 5/8%, Due December 1, 2011................................         93,750         100,000
  Unamortized debt discount...................................         (8,304)         (8,262)
Convertible Subordinated Debentures
  7 1/4%, Due December 15, 2015...............................        246,205         246,205
  Unamortized debt discount...................................         (1,840)         (1,970)
9.94% Unsecured loan due January 1, 1999......................         12,000          16,000
                                                                   ----------      ----------
     Total....................................................     $1,291,811      $1,151,973
                                                                   ==========      ==========
---------------------------------------------------------------------------------------------
</TABLE>
 
The aggregate principal amounts of the Company's debentures maturing in the
years 1996 through 2000 are: $6,250,000; $106,250,000; $156,250,000;
$113,375,000 and $22,080,000.
 
Discounts and the expenses incurred in connection with the issuance of
debentures are being amortized on a basis which will equitably distribute the
amount to "Interest on long-term debt" over the life of each debenture issue.
 
The Company's 7 1/4% Convertible Subordinated Debentures, which mature on
December 15, 2015, are convertible into shares of the Company's common stock at
any time prior to maturity at an initial conversion price of $54 per share.
Under additional terms of the issue, on December 15, 2000, the Company is
obligated to purchase, at the option of the holder, any debenture then
outstanding for 100% of the principal amount plus accrued interest.
 
The 9.94% unsecured loan due January 1, 1999, is an obligation of Virginia
Natural Gas. This $20,000,000 loan, which is being repaid in five annual
installments of $4,000,000 each beginning January 1, 1995, has been guaranteed
by the Company.
 
RESTRICTIONS UNDER CERTAIN DEBT AGREEMENTS
At December 31, 1995, the Company had senior debentures outstanding under a 1971
indenture between the Company and Chemical Bank, as trustee (the 1971
Indenture). The 1971 Indenture contains covenants which limit, among other
things, the incurrence of funded debt. Funded debt is indebtedness maturing (or,
at the Company's option, renewable or extendable for) more than one year after
the date of issuance. One of the covenants contained in the 1971 Indenture
provides that the Company may not issue funded debt unless (a) consolidated
income available for interest and subsidiary preferred stock dividends (computed
before income and excess or other profits taxes) of the Company for any twelve
consecutive months within the preceding fifteen months shall have been not less
than 2 1/2 times the sum of the total annual interest charges upon the funded
debt of the Company and the total annual dividend requirements on subsidiary
preferred stock, in each case to be outstanding immediately thereafter and (b)
after giving effect to such issuance the sum of the principal amount of
 
                                       61
<PAGE>   64
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

funded debt of the Company outstanding and the amount of subsidiary preferred
stock outstanding shall not be more than 60 percent of the consolidated net
tangible assets of the Company. The Company has a shelf registration with the
SEC for the sale of up to $350 million of debt securities. Debt securities to be
issued under this shelf registration would be classified as funded debt and,
therefore, the 1971 Indenture limits the Company's ability to issue such
securities if the provisions of the covenant summarized above are not met.
 
As a result of the charges in 1995 for workforce reduction costs and write-downs
of gas and oil producing properties and coal properties, the Company's ability
to issue funded debt is expected to be restricted through May 1996.
 
14.     SHORT-TERM BORROWINGS
The weighted average interest rate on the Company's commercial paper notes
outstanding at December 31, 1994 and 1995, was 5.86% and 5.79%, respectively.
 
The Company entered into a $475,000,000 credit agreement and a $300,000,000
credit agreement effective June 30, 1995. These agreements replaced existing
credit agreements that were terminated on that same date. Borrowings under these
agreements are in the form of revolving credits and may, at the option of the
Company, be structured either as syndicated loans by a group of participating
banks or money market loans by individual participating banks. The loans may be
borrowed, paid or repaid and reborrowed on a few days notice. Varying interest
rate options are available for syndicated loans, while the interest rate on
money market loans is determined from quotes rendered by the participating
banks. These agreements may be used for general corporate purposes, including
the support of commercial paper notes. The agreements are currently scheduled to
expire on June 29, 1996; however, the Company expects that the agreements will
be renewed or replaced by comparable agreements. A facility fee is charged under
the agreements but is not considered significant. There were no borrowings under
these agreements at December 31, 1995.
 
15.     FINANCIAL INSTRUMENTS
FAIR VALUES
The estimated fair value of the Company's long-term debt, including current
maturities, was as follows at December 31, 1994 and 1995:
 
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------
                                                 1995                            1994
                                      ---------------------------     ---------------------------
                                       Carrying          Fair          Carrying          Fair
December 31,                            Amount           Value          Amount           Value
-------------------------------------------------------------------------------------------------
<S>                                   <C>             <C>             <C>             <C>
                                                            (In Thousands)
Long-term debt.....................   $1,312,205      $1,368,002      $1,166,205      $1,095,492
-------------------------------------------------------------------------------------------------
</TABLE>
 
The fair values were estimated based upon closing transactions and/or quotations
for the Company's debentures as of those dates. Temporary cash investments and
commercial paper notes are stated at amounts which approximate fair value due to
the short maturities of those financial instruments.
 
DERIVATIVE FINANCIAL INSTRUMENTS AND ENERGY PRICE RISK MANAGEMENT ACTIVITIES
The majority of the Company's energy price risk management activities involve
exchange-traded futures and options contracts which can be settled through the
purchase or delivery of commodities. The Company's nonregulated subsidiaries use
futures and options to manage commodity price risk in connection with the
production, purchase and sale of natural gas and oil, and for stored gas
inventories. At December 31, 1995, the Company's price risk management
activities included futures contracts under hedging activities maturing through
May 1997 covering 11.2 billion cubic feet (Bcf) of natural gas and
 
                                       62
<PAGE>   65
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

107,000 barrels of oil. Since these contracts qualify and have been designated
as hedges, any gains or losses resulting from market price changes are expected
to be generally offset by the related physical transaction. The net unrealized
gain related to these futures contracts was approximately $1,500,000 at December
31, 1995.
 
In addition to exchange-traded futures and options contracts, the nonregulated
subsidiaries periodically enter into OTC price swap agreements to manage their
exposure to commodity price risk under existing sales commitments. At December
31, 1995, the Company's nonregulated subsidiaries had swap agreements of varying
duration outstanding with several counterparties to exchange monthly payments on
net notional quantities of 30.3 Bcf of gas over the ensuing 3 years. Net
notional quantities or amounts do not represent the quantities or amounts
exchanged by the parties and, thus, are not a measure of the exposure of the
Company through its use of derivatives. The amounts exchanged are calculated on
the basis of monthly notional quantities and other terms of the agreements. The
net unrealized loss related to these swap agreements was approximately
$2,600,000 at December 31, 1995. Profits expected on anticipated sales related
to the hedged transactions should generally offset the estimated unrealized
losses on the swap agreements. CNG Energy Services has also entered into a
10-year foreign currency swap agreement to manage foreign exchange rate risk in
connection with the payment of demand charges for pipeline capacity in Canada.
The aggregate notional amount underlying this swap agreement was approximately
$72,500,000 at December 31, 1995. The unrealized gain related to the foreign
currency swap agreement was approximately $2,100,000 at December 31, 1995.
 
The use of futures and options contracts and derivative financial instruments
exposes the Company to market risk and credit risk. Market risk represents the
potential loss that can be caused by a change in the market value of a
particular commitment. Although the use of exchange-traded and OTC instruments
generally reduces market risk exposure due to unfavorable price fluctuations,
such risk management activities, while not significant, can also result in the
assumption of a limited degree of price risk in certain isolated transactions.
Credit risk relates to the risk of loss that the Company would incur as a result
of nonperformance by counterparties pursuant to the terms of their contractual
obligations. The Company does not have a significant exposure to any individual
counterparty to its energy price risk management activities. Management has
operating procedures in place to evaluate market and credit risks and believes
that the Company's exposure to risks associated with exchange-traded futures and
options contracts and derivative financial instruments is not material in
relation to the Company's financial position, results of operations or cash
flows.
 
16.     ENVIRONMENTAL MATTERS
The Company is subject to various federal, state and local laws and regulations
relating to the protection of the environment. These laws and regulations govern
both current and future operations and potentially extend to plant sites
formerly owned or operated by the subsidiaries, or their predecessors.
 
The Company has taken a proactive position with respect to environmental
concerns. As part of normal business operations, subsidiaries periodically
monitor their properties and facilities to identify and resolve potential
environmental matters, and the Company conducts general environmental surveys on
a continuing basis at its operating facilities to monitor compliance with
environmental laws and regulations. As part of this process, voluntary surveys
at subsidiary sites have been conducted to determine the extent of any possible
soil contamination due to hazardous substances, such as mercury, and when
contamination has been discovered remediation efforts are undertaken. Further,
on August 16, 1990, CNG Transmission entered into a Consent Order and Agreement
with the Commonwealth of Pennsylvania Department of Environmental Resources
(DER) in which CNG Transmission has agreed with the DER's determination of
certain violations of the Pennsylvania Solid Waste Management Act, the
Pennsylvania Clean Streams Law and the rules and regulations promulgated
thereunder. No civil penalties have been assessed as of this date. Pursuant to
the Order and Agreement, CNG Transmission
 
                                       63
<PAGE>   66
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

is performing sampling, testing and analysis, and conducting a program of
remediation at some of its Pennsylvania facilities. Total remediation costs in
connection with these sites and the Order and Agreement are not expected to be
material with respect to the Company's financial position, results of operations
or cash flows. Based on current information, the Company has recognized a gross
estimated liability amounting to $22,004,000 at December 31, 1995, for future
costs expected to be incurred to remediate or mitigate hazardous substances at
these sites and at facilities covered by the Order and Agreement.
 
Inasmuch as certain environmental-related expenditures are expected to be
recoverable in future regulatory proceedings, a regulatory asset amounting to
$13,932,000 at December 31, 1995, is included in the Consolidated Balance Sheet
under the caption "Deferred charges and other assets." Also, uncontested claims
amounting to $3,669,000 at December 31, 1995, were recognized for environmental-
related costs probable for recovery through joint-interest operating agreements.
 
The total amounts included in operating expenses for remediation and other
environmental-related costs, and the components of such costs, are as follows:
 
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
Years Ended December 31,                                          1995        1994        1993
-----------------------------------------------------------------------------------------------
                                                                        (In Thousands)
<S>                                                             <C>         <C>         <C>
Recurring costs for ongoing operations.....................      $3,094      $3,479      $3,381
Mandated remediation and other compliance costs............       2,307         214       3,963
Voluntary remediation costs................................       1,630         507       1,185
Other......................................................          79          28         520
                                                                -------     -------     -------
  Total....................................................      $7,110      $4,228      $9,049
                                                                 ======      ======      ======
-----------------------------------------------------------------------------------------------
</TABLE>
 
CNG Transmission and certain of the distribution subsidiaries are subject to the
Federal Clean Air Act (Clean Air Act) and the Federal Clean Air Act Amendments
of 1990 (1990 amendments) which added significantly to the existing Clean Air
Act requirements. As a result of the 1990 amendments, these subsidiaries were
required to install Reasonably Available Control Technology (RACT) at some
compressor stations by May 31, 1995, to reduce nitrogen oxide emissions.
Compliance requires capital expenditures to similarly retrofit some of the
compressor engines along the Company's pipeline system. In this regard,
approximately $23.3 million was expended in 1994 to install emission control
equipment. During 1995, the Company expended $11.3 million to retrofit existing
engines with emission control equipment to meet the RACT requirements and to
comply with certification standards under the 1990 amendments. All required
permit applications have been filed with the appropriate federal and state
agencies and have been approved or are pending approval. The Company anticipates
spending an additional $2.4 million during 1996. The total capital expenditures
required to comply with the 1990 amendments are expected to be recoverable
through future regulatory proceedings.
 
The Company has determined that it is associated with 16 former manufactured gas
plant sites, five of which are currently owned by subsidiaries. Studies
conducted by other utilities at their former manufactured gas plants have
indicated that their sites contain coal tar and other potentially harmful
materials. None of the 16 former sites with which the Company is associated is
under investigation by any state or federal environmental agency, and no
investigation or action is currently anticipated. At this time it is not known
if, or to what degree, these sites may contain environmental contamination.
Therefore, the Company is not able to estimate the cost, if any, that may be
required for the possible remediation of these sites.
 
The Company discovered in the course of conducting a routine environmental
survey at East Ohio Gas that some of its practices for collecting and handling
pipeline fluids that may have been contaminated with polychlorinated biphenyls
(PCBs) may not have complied with environmental regulations. The
 
                                       64
<PAGE>   67
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

appropriate agencies have been notified as part of the federal self-disclosure
process and discussions are continuing with the agencies to gain approval of
revised collection and handling procedures. A thorough investigation of all
collection and handling practices at East Ohio Gas is ongoing and the results of
this investigation will be provided to the appropriate agencies. The
discrepancies in the procedures were primarily in connection with recordkeeping
and did not involve spills, leaks, or other mishandling of PCB contaminated
fluids and did not damage the environment. The Company anticipates that
penalties, if any, incurred in connection with this matter may be mitigated as a
result of the Company's self disclosure. The amount of any liabilities in
connection with this matter is not expected to be material with respect to the
Company's financial position, results of operations or cash flows.
 
Estimates of liability in the environmental area are based on current
environmental laws and regulations and existing technology. The exact nature of
environmental issues which the Company may encounter in the future cannot be
predicted. Additional environmental liabilities may result in the future as more
stringent environmental laws and regulations are implemented and as the Company
obtains more specific information about its existing sites and production
facilities. At present, no estimate of any such additional liability, or range
of liability amounts, can be made. However, the amount of any such liabilities
could be material.
 
17.     COMMITMENTS AND CONTINGENCIES
Lease arrangements of the subsidiaries are principally for office space,
business machines and transportation equipment. None of these arrangements,
individually or in the aggregate, are material capital leases. Rental expense
incurred in the years 1993 through 1995 was not material, and future rental
payments required under leases in effect at December 31, 1995, are not material.
 
It is estimated that the Company's 1996 capital budget will amount to
$455,200,000, and that approximately $180,600,000 of that amount will be
directed to gas and oil producing activities. In connection with the capital
budget, the subsidiaries have entered into certain contractual commitments.
 
The subsidiaries have claims and suits pending against them, but, in the opinion
of management and counsel, the ultimate liability will not have a material
effect on the Company's financial position, results of operations or cash flows.
 
18.     DISAGGREGATED INFORMATION
In addition to operating in all phases of the natural gas business, the Company
explores for and produces oil and provides a variety of energy marketing
services.
 
Distribution represents the retail gas distribution subsidiaries. These
subsidiaries sell gas and/or provide transportation services to residential,
commercial and industrial customers in Ohio, Pennsylvania, Virginia and West
Virginia, and are subject to price regulation by their respective state utility
commissions.
 
Transmission operations include the activities of CNG Transmission, an
interstate pipeline company regulated by the FERC which provides gas
transportation, storage and related services to affiliates and to utilities and
end users in the Midwest, the Mid-Atlantic states and the Northeast.
Transmission operations also include, prior to April 1, 1995, the activities of
CNG Storage. CNG Storage is engaged in providing natural gas storage facilities
and a wide range of storage-related services to affiliates and other customers,
including the sale or lease of base gas, and the sale, lease or brokerage of gas
storage capacity obtained from third parties.
 
Exploration and production includes the results of CNG Producing and the gas and
oil production activities of CNG Transmission. These operations are located
throughout the United States and in the Gulf of Mexico. CNG Producing also owns
a working interest in a heavy oil program in Alberta, Canada.
 
                                       65
<PAGE>   68
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Energy marketing services is comprised of CNG Energy Services, CNG Power, CNG
Power Services and, for the period April 1, 1995 through December 31, 1995, CNG
Storage. CNG Energy Services markets Company-owned gas production and arranges
gas supplies, transportation, storage and related services throughout North
America. CNG Power develops new business opportunities for the Company in
energy-related markets. It invests in and develops independent power producer
projects and conducts a gas liquids business. CNG Power Services, created in
1994, is the power marketing subsidiary of the Company and has received FERC
approval to purchase and resell electricity at market-based rates. Except for
CNG Storage, the operations of these subsidiaries, if applicable, were included
in the "Other" category for 1993 and 1994.
 
The activities of Consolidated LNG, CNG Research and CNG Coal are included in
the "Other" category.
 
Transactions between affiliates are recognized at prices which approximate
market value. Significant transactions between the operating components are
eliminated to reconcile the disaggregated information to consolidated amounts.
Identifiable assets of each component are those assets that are used in its
operations.
 
                                       66
<PAGE>   69
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presents disaggregated information pertaining to the
Company's operations:
 
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------------
                                                          Exploration      Energy
                                                              and        Marketing                 Corporate and
                          Distribution    Transmission    Production      Services      Other       Eliminations       Total
-------------------------------------------------------------------------------------------------------------------------------
<S>                       <C>             <C>             <C>            <C>           <C>         <C>               <C>
                                                                    (In Thousands)
1995
Operating revenues
  Nonaffiliated.........   $ 1,738,947     $  365,888     $   174,442    $1,020,789    $  7,259      $       --      $3,307,325
  Affiliated............         6,280        105,138         187,012        87,611      10,168        (396,209)             --
                           -----------     ----------     -----------    ----------    --------      ----------      ----------
      Total.............     1,745,227        471,026         361,454     1,108,400      17,427        (396,209)      3,307,325
Other operating
  expenses..............     1,466,776        261,091         438,477     1,113,014      14,543        (392,668)      2,901,233
Depreciation and
  amortization..........        70,972         59,552         123,492         1,072          --           1,548         256,636
                           -----------     ----------     -----------    ----------    --------      ----------      ----------
Operating income before
  income taxes..........   $   207,479     $  150,383     $  (200,515)   $   (5,686)   $  2,884      $   (5,089)     $  149,456
                           ===========     ==========     ===========    ==========    ========      ==========      ==========
Capital expenditures....   $   160,480     $   81,557     $   176,789    $   19,567    $     --      $    1,000      $  439,393
Identifiable assets.....   $ 2,645,004     $1,483,631     $ 1,155,092    $  317,490    $ 54,425      $ (237,349)     $5,418,293
-------------------------------------------------------------------------------------------------------------------------------
1994
Operating revenues
  Nonaffiliated.........   $ 1,804,317     $  348,141     $   411,876    $       --    $471,694      $       --      $3,036,028
  Affiliated............         1,296        111,147          77,564            --      44,966        (234,973)             --
                           -----------     ----------     -----------    ----------    --------      ----------      ----------
      Total.............     1,805,613        459,288         489,440            --     516,660        (234,973)      3,036,028
Other operating
  expenses..............     1,579,259        259,078         299,872            --     508,303        (233,206)      2,413,306
Depreciation and
  amortization..........        67,401         53,944         155,558            --         736           1,678         279,317
                           -----------     ----------     -----------    ----------    --------      ----------      ----------
Operating income before
  income taxes..........   $   158,953     $  146,266     $    34,010    $       --    $  7,621      $   (3,445)     $  343,405
                           ===========     ==========     ===========    ==========    ========      ==========      ==========
Capital expenditures....   $   146,882     $  108,647     $   166,022    $       --    $ 15,198      $    1,036      $  437,785
Identifiable assets.....   $ 2,595,615     $1,543,790     $ 1,372,747    $       --    $283,799      $ (277,278)     $5,518,673
-------------------------------------------------------------------------------------------------------------------------------
1993
Operating revenues
  Nonaffiliated.........   $ 1,772,816     $  689,772     $   437,125    $       --    $284,372      $       --      $3,184,085
  Affiliated............         1,112        293,984          99,301            --      73,401        (467,798)             --
                           -----------     ----------     -----------    ----------    --------      ----------      ----------
      Total.............     1,773,928        983,756         536,426            --     357,773        (467,798)      3,184,085
Other operating
  expenses..............     1,541,741        789,894         312,393            --     351,800        (463,735)      2,532,093
Depreciation and
  amortization..........        65,295         50,418         176,738            --         292           1,905         294,648
                           -----------     ----------     -----------    ----------    --------      ----------      ----------
Operating income before
  income taxes..........   $   166,892     $  143,444     $    47,295    $       --    $  5,681      $   (5,968)     $  357,344
                           ===========     ==========     ===========    ==========    ========      ==========      ==========
Capital expenditures....   $   115,376     $  113,385     $   110,746    $       --    $  1,757      $    1,305      $  342,569
Identifiable assets.....   $ 2,519,247     $1,574,047     $ 1,363,065    $       --    $267,033      $ (286,204)     $5,437,188
-------------------------------------------------------------------------------------------------------------------------------
</TABLE>
 
                                       67
<PAGE>   70
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19.     SUPPLEMENTARY FINANCIAL INFORMATION--UNAUDITED
(A)    GAS AND OIL PRODUCING ACTIVITIES (EXCLUDING COST-OF-SERVICE
RATE-REGULATED ACTIVITIES)
This information has been prepared in accordance with SFAS No. 69, "Disclosures
about Oil and Gas Producing Activities," and related SEC pronouncements.
Statement No. 69 is a comprehensive, standard set of required disclosures about
the gas and oil producing activities of publicly traded companies. The following
disclosures exclude the gas and oil producing activities subject to
cost-of-service rate regulation. Certain disclosures about these gas and oil
activities, which are exempt from the accounting methods prescribed by the SEC,
are included under "Cost-of-Service Properties" in this Note (A).
 
        CAPITALIZED COSTS
The aggregate amounts of costs capitalized by subsidiaries for their gas and oil
producing activities, and related aggregate amounts of accumulated depreciation
and amortization, follow:
 
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
December 31,                                                           1995            1994
----------------------------------------------------------------------------------------------
<S>                                                                <C>             <C>
                                                                         (In Thousands)
Capitalized costs of
  Proved properties...........................................     $ 2,871,560     $ 2,796,911
  Unproved properties.........................................         270,315         255,490
                                                                   -----------     -----------
     Subtotal.................................................       3,141,875       3,052,401
                                                                   -----------     -----------
Accumulated depreciation of
  Proved properties...........................................       2,090,498       1,855,398
  Unproved properties.........................................         116,256          86,887
                                                                   -----------     -----------
     Subtotal.................................................       2,206,754       1,942,285
                                                                   -----------     -----------
     Net capitalized costs....................................     $   935,121     $ 1,110,116
                                                                   ===========     ===========
----------------------------------------------------------------------------------------------
</TABLE>
 
As described in Note 3, the Company was required to recognize an impairment of
its gas and oil producing properties at March 31, 1995. The non-cash charge
amounted to $226,209,000 and is reflected in the 1995 amounts included above.
 
        TOTAL COSTS INCURRED
The following costs were incurred by subsidiaries in their gas and oil producing
activities during the years 1993 through 1995:
 
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
Years Ended December 31,                                    1995          1994          1993
----------------------------------------------------------------------------------------------
<S>                                                      <C>           <C>           <C>
                                                                     (In Thousands)
Property acquisition costs
  Proved properties.................................     $   5,824     $   4,000     $     132
  Unproved properties...............................         9,686        18,998        18,224
                                                         ---------     ---------     ---------
     Subtotal.......................................        15,510        22,998        18,356
Exploration costs...................................        50,974        48,514        47,934
Development costs...................................       102,574        82,020        40,516
                                                         ---------     ---------     ---------
     Total..........................................     $ 169,058     $ 153,532     $ 106,806
                                                         =========     =========     =========
----------------------------------------------------------------------------------------------
</TABLE>
 
        RESULTS OF OPERATIONS
The elements of the "results of operations for gas and oil producing activities"
that follow are as required and defined by the FASB. The Company cautions that
these standardized disclosures do not represent
 
                                       68
<PAGE>   71
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

the results of operations based on its historical financial statements. In
addition to requiring different determinations of revenues and costs, the
disclosures exclude the impact of interest expense and corporate overheads.
 
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
Years Ended December 31,                                   1995           1994          1993
----------------------------------------------------------------------------------------------
<S>                                                     <C>            <C>           <C>
                                                                     (In Thousands)
Revenues (net of royalties) from:
  Sales to nonaffiliated companies.................     $  60,139      $ 201,820     $ 204,614
  Transfers to other operations....................       150,930         55,007        88,241
                                                        ---------      ---------     ---------
     Total.........................................       211,069        256,827       292,855
                                                        ---------      ---------     ---------
Less: Production (lifting) costs...................        40,812         42,723        49,177
      Depreciation and amortization................       117,163        150,936       173,171
      Impairment of producing properties...........       226,209             --            --
      Income tax expense...........................       (68,615)        15,446        18,400
                                                        ---------      ---------     ---------
Results of operations..............................     $(104,500)     $  47,722     $  52,107
                                                        ==========     =========     =========
----------------------------------------------------------------------------------------------
</TABLE>
 
       COMPANY-OWNED RESERVES (NON-COST-OF-SERVICE RESERVES)
Estimated net quantities of proved gas and oil (including condensate) reserves
in the United States and Canada at December 31, 1993 through 1995, and changes
in the reserves during those years, are shown in the two schedules which follow:
 
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------
Years Ended December 31,                                             1995      1994      1993
---------------------------------------------------------------------------------------------
<S>                                                                  <C>       <C>       <C>
                                                                             (In Bcf)
PROVED DEVELOPED AND UNDEVELOPED RESERVES*--GAS
  At January 1..................................................      901       885       918
  Changes in reserves
     Extensions, discoveries and other additions................      167       111        55
     Revisions of previous estimates............................       17        16        46
     Production.................................................     (103)     (114)     (124)
     Purchases of gas in place..................................        7         8        --
     Sales of gas in place......................................       (4)       (5)      (10)
                                                                     ----      ----      ----
  At December 31................................................      985       901       885
                                                                     ====      ====      ====
PROVED DEVELOPED RESERVES*--GAS
  At January 1..................................................      730       761       794
  At December 31................................................      717       730       761
* Net before royalty.
---------------------------------------------------------------------------------------------
</TABLE>
 
Included in the caption "Extensions, discoveries and other additions" for 1994
and 1995 are 56 and 110 Bcf, respectively, of proved undeveloped reserves for
which development costs will be incurred in future years. The preceding proved
developed and undeveloped gas reserves at December 31, 1993 through 1995,
include United States reserves of 884, 900 and 984 Bcf which, together with the
Canadian
 
                                       69
<PAGE>   72
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
reserves and the gas reserves reported under "Cost-of-Service Properties," are
as contained in reports of Ralph E. Davis Associates, Inc., independent
geologists.
 
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
Years Ended December 31,                                         1995        1994        1993
----------------------------------------------------------------------------------------------
<S>                                                             <C>         <C>         <C>
                                                                      (In Thousand Bbls)
PROVED DEVELOPED AND UNDEVELOPED RESERVES*--OIL
  At January 1.............................................     46,255      27,596      29,238
  Changes in reserves
     Extensions, discoveries and other additions...........      1,965      24,709       1,978
     Revisions of previous estimates.......................      1,117      (2,791)        290
     Production............................................     (3,132)     (3,333)     (3,907)
     Purchases of oil in place.............................        163          77          --
     Sales of oil in place.................................       (577)         (3)         (3)
                                                                ------      ------      ------
  At December 31...........................................     45,791      46,255      27,596
                                                                ======      ======      ======
PROVED DEVELOPED RESERVES*--OIL
  At January 1.............................................     20,379      21,936      27,449
  At December 31...........................................     19,838      20,379      21,936
* Net before royalty.
----------------------------------------------------------------------------------------------
</TABLE>
 
Included in the caption "Extensions, discoveries and other additions" for 1994
are 22,305 thousand barrels of proved undeveloped reserves for which development
costs will be incurred in future years. The foregoing proved developed and
undeveloped oil reserves at December 31, 1993 through 1995, include United
States reserves of 21,917, 40,918 and 39,964 thousand barrels, respectively.
These, together with the Canadian reserves and the oil reserves reported under
"Cost-of-Service Properties," are as contained in reports of Ralph E. Davis
Associates, Inc.
 
       STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES
THEREIN
The following tabulation has been prepared in accordance with the FASB's rules
for disclosure of a standardized measure of discounted future net cash flows
relating to Company-owned proved gas and oil reserve quantities.
 
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
December 31,                                            1995            1994            1993
-----------------------------------------------------------------------------------------------
<S>                                                 <C>             <C>             <C>
                                                                  (In Thousands)
Future cash inflows............................     $ 2,668,837     $ 2,303,024     $ 2,336,553
Less: Future development and production
  costs........................................         659,532         626,344         529,592
      Future income tax expense................         602,158         490,079         537,966
                                                    -----------     -----------     -----------
Future net cash flows..........................       1,407,147       1,186,601       1,268,995
Less annual discount (10% a year)..............         565,404         482,109         500,732
                                                    -----------     -----------     -----------
Standardized measure of discounted future
  net cash flows...............................     $   841,743     $   704,492     $   768,263
                                                    ===========     ===========     ===========
-----------------------------------------------------------------------------------------------
</TABLE>
 
In the foregoing determination of future cash inflows, sales prices for gas were
based on contractual arrangements or market prices at each year end. Prices for
oil were based on average prices received from sales in the month of December
each year. Future costs of developing and producing the proved gas and oil
reserves reported at the end of each year shown were based on costs determined
at each such year end, assuming the continuation of existing economic
conditions. Future income taxes were computed by applying the appropriate
year-end or future statutory tax rate to future pretax net cash
 
                                       70
<PAGE>   73
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

flows, less the tax basis of the properties involved, and giving effect to tax
deductions, or permanent differences and tax credits.
 
It is not intended that the FASB's standardized measure of discounted future net
cash flows represent the fair market value of the Company's proved reserves. The
Company cautions that the disclosures shown are based on estimates of proved
reserve quantities and future production schedules which are inherently
imprecise and subject to revision, and the 10% discount rate is arbitrary. In
addition, present costs and prices are used in the determinations and no value
may be assigned to probable or possible reserves.
 
The following tabulation is a summary of changes between the total standardized
measure of discounted future net cash flows at the beginning and end of each
year.
 
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------
Years Ended December 31,                                 1995           1994           1993
---------------------------------------------------------------------------------------------
<S>                                                   <C>            <C>            <C>
                                                                  (In Thousands)
Standardized measure of discounted future net
  cash flows at January 1........................     $ 704,492      $ 768,263      $ 818,352
Changes in the year resulting from
  Sales and transfers of gas and oil produced
     during the year, less production costs......      (170,257)      (214,104)      (243,678)
  Prices and production and development costs
     related to future production................       150,634       (153,962)        12,635
  Extensions, discoveries and other additions,
     less production and development costs.......       181,664        144,342         99,662
  Previously estimated development costs
     incurred during the year....................        62,958         46,568          4,838
  Revisions of previous quantity estimates.......         8,336          4,228         66,506
  Accretion of discount..........................        98,736        108,417        109,287
  Income taxes...................................       (70,927)        33,029        (41,395)
  Purchases and sales of proved reserves in
     place-net...................................         1,794          4,122         (5,439)
  Other (principally timing of production).......      (125,687)       (36,411)       (52,505)
                                                      ---------      ---------      ---------
Standardized measure of discounted future net
  cash flows at December 31......................     $ 841,743      $ 704,492      $ 768,263
                                                      =========      =========      =========
---------------------------------------------------------------------------------------------
</TABLE>
 
       COST-OF-SERVICE PROPERTIES
As previously stated, activities subject to cost-of-service rate regulation are
excluded from the foregoing information. At December 31, 1994 and 1995, net
capitalized costs of cost-of-service properties amounted to $25,244,000 and
$14,809,000, respectively. Related proved reserves of gas and oil are located in
the United States, and amounted to 75, 71 and 56 Bcf of gas at December 31, 1993
through 1995, and 287 and 256 thousand barrels of oil at December 31, 1993 and
1994, respectively. There were no cost-of-service oil reserves at December 31,
1995. East Ohio Gas sold all of its remaining gas and oil reserves during 1995.
Production for the years 1993 through 1995 amounted to 6, 6 and 4 Bcf of gas and
29, 24 and 17 thousand barrels of oil, respectively.
 
Future revenues associated with production of the foregoing gas and oil reserves
would be based upon cost-of-service ratemaking and historical asset costs, with
rate of return levels determined by various state regulatory commissions.
 
                                       71
<PAGE>   74
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
 
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(B) QUARTERLY FINANCIAL DATA
A summary of the quarterly results of operations for the years 1994 and 1995
follows. Because a major portion of the gas sold or transported by the Company's
distribution and transmission operations is ultimately used for space heating,
both revenues and earnings are subject to seasonal fluctuations, and third
quarter results are usually the least significant of the year for the Company.
Seasonal fluctuations are further influenced by the timing of price relief
granted under regulation to compensate for certain past cost increases.
 
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
                                                                    Quarter
                                              -------------------------------------------------
                                                First*       Second**     Third***      Fourth
-----------------------------------------------------------------------------------------------
<S>                                           <C>            <C>          <C>          <C>
                                                               (In Thousands)
1995
Total operating revenues...................   $1,191,637     $664,972     $515,142     $935,574
Operating income before income taxes.......      (15,918)       2,999        1,956      160,419
Net income (loss)..........................      (21,396)     (33,512)     (11,215)      87,467
Earnings (loss) per share of common
  stock....................................         (.23)        (.36)        (.12)         .94

1994
Total operating revenues...................   $1,213,596     $582,008     $451,829     $788,595
Operating income before income taxes.......      217,439       22,141      (17,990)     121,815
Net income (loss)..........................      130,918        3,069      (24,557)      73,741
Earnings (loss) per share of common
  stock....................................         1.41          .03         (.26)         .79

<FN>
  * The 1995 first quarter includes the effect of an impairment of gas and oil producing
    properties that reduced operating income before income taxes by $226,209,000 and net income
    by $145,000,000, or $1.56 per share (see Note 3 to the consolidated financial statements).
 ** The 1995 second quarter includes charges related to workforce reductions that reduced
    operating income before income taxes by $36,412,000 and net income by $23,668,000, or $.25
    per share. Net income was also reduced by the write-down of coal properties amounting to
    $20,323,000, or $.22 per share (see Notes 3 and 4 to the consolidated financial
    statements).
*** The 1995 third quarter includes charges related to workforce reductions that reduced
    operating income before income taxes by $3,457,000 and net income by $2,343,000, or $.02
    per share (see Note 4 to the consolidated financial statements).
-----------------------------------------------------------------------------------------------
</TABLE>
 
                                       72
<PAGE>   75
 
ITEM 8.        CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Concl.)
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)
 
(C)    COMMON STOCK MARKET PRICES AND RELATED MATTERS
At December 31, 1995, there were 38,516 holders of the Company's common stock.
The principal market for the stock is the New York Stock Exchange. Quarterly
price ranges and dividends declared on the common stock for the years 1994 and
1995 follow. Restrictions on the payment of dividends are discussed in Note 12.
 
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
                                                                        Quarter
                                                         -------------------------------------
                                                         First     Second     Third     Fourth
----------------------------------------------------------------------------------------------
<S>                                                      <C>       <C>       <C>       <C>
Market Price Range
1995 --High..........................................    $38 3/4   $40       $41       $46 1/4
     --Low...........................................    $33 5/8   $35 1/8   $35 3/4   $37 3/8

1994 --High..........................................    $47       $40       $41 1/8   $39
     --Low...........................................    $38 3/4   $36 3/4   $37 1/2   $33 3/8

Dividends Declared per Share
1995.................................................    $ .485    $ .485    $ .485    $ .485
1994.................................................    $ .485    $ .485    $ .485    $ .485
----------------------------------------------------------------------------------------------
</TABLE>
 
                                       73
<PAGE>   76
 
ITEM 9.     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
            AND FINANCIAL DISCLOSURE
 
Not applicable
 
                                    PART III
 
ITEM 10.     DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
 
Information concerning the directors of the Company is hereby incorporated by
reference to the Company's definitive proxy statement filed with the Commission
pursuant to Regulation 14A within 120 days after the close of the Company's
fiscal year. Information concerning the executive officers of the Company is on
page 16 of this Report.
 
ITEM 11.     EXECUTIVE COMPENSATION
 
This information is hereby incorporated by reference to the Company's definitive
proxy statement filed with the Commission pursuant to Regulation 14A within 120
days after the close of the Company's fiscal year.
 
ITEM 12.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
 
This information is hereby incorporated by reference to the Company's definitive
proxy statement filed with the Commission pursuant to Regulation 14A within 120
days after the close of the Company's fiscal year.
 
ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
 
This information is hereby incorporated by reference to the Company's definitive
proxy statement filed with the Commission pursuant to Regulation 14A within 120
days after the close of the Company's fiscal year.
 
                                    PART IV
 
ITEM 14.     EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
 
REPORTS ON FORM 8-K
 
No reports on Form 8-K were filed during the last quarter of the calendar year
1995, the year for which this Form 10-K is being filed.
 
On January 23, 1996, the Company filed a Current Report on Form 8-K with the SEC
regarding a Rights Agreement (see Note 10 to the consolidated financial
statements, page 58).
 
DOCUMENTS FILED AS A PART OF THIS REPORT
 
     Financial Statements
 
All of the financial statements filed as a part of this Report are included in
ITEM 8 and reference is made to the index on page 39.
 
                                       74
<PAGE>   77
 
ITEM 14.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Continued)
 
     Consent of Independent Accountants
 
We hereby consent to the incorporation by reference in the Prospectuses
constituting part of the Registration Statements on Form S-3 (Nos. 33-1040,
33-52585 and 33-63931) and Form S-8 (Nos. 2-77204, 2-97948, 33-40478 and
33-44892) of Consolidated Natural Gas Company of our report dated February 20,
1996, appearing on page 40 of this Form 10-K. We also consent to the references
to us under the heading "Experts" in such Prospectuses.
 
PRICE WATERHOUSE LLP
 
600 Grant Street
Pittsburgh, Pennsylvania 15219-9954
March 27, 1996
 
<TABLE>
<CAPTION>
EXHIBITS
---------------------------------------------------------------------------------------------
 SEC
Exhibit
Number                                      Description of Exhibit
---------------------------------------------------------------------------------------------
<C>      <S>      <C>
  (3)    Articles of Incorporation and By-Laws:
         (3A)     Certificate of Incorporation of Consolidated Natural Gas Company, restated
                  October 4, 1990 (incorporated by reference to Exhibit A-1 to the
                  Application-Declaration of Consolidated Natural Gas Company on Form U-1,
                  File No. 70-7811)

         (3B)     By-Laws of Consolidated Natural Gas Company, last amended March 1, 1993
                  (incorporated by reference to Exhibit (3B) filed with Consolidated Natural
                  Gas Company's Form 10-K for the year ended December 31, 1992, File No.
                  1-3196)

  (4)    Instruments Defining the Rights of Security Holders, Including Indentures:
         (4A)     (1) Indentures of Consolidated Natural Gas Company:
                  Indentures of Consolidated Natural Gas Company are incorporated by
                  reference to previously filed material as indicated on the list filed
                  herewith
                  (2) Note Purchase Agreement of Virginia Natural Gas:
                  Note Purchase Agreement dated as of January 1, 1989, between Virginia
                  Natural Gas, Inc. and the Aid Association for Lutherans relating to
                  $20,000,000 principal amount of 9.94% Senior Notes, Series A, due January
                  1, 1999 (incorporated by reference to Exhibit B-1 to the
                  Application-Declaration of Consolidated Natural Gas Company on Form U-1,
                  File No. 70-7667)

         (4B)     Section 203 of the Delaware General Corporation Law, "Business Combinations
                  With Interested Stockholders," effective February 2, 1988 (incorporated by
                  reference to Exhibit (4B) filed with Consolidated Natural Gas Company's
                  Form 10-K for the year ended December 31, 1987, File No. 1-3196)
                  Other portions of the Delaware General Corporation Law affecting security
                  holder rights are considered routine and are not filed hereunder

          (4C)    Description of Consolidated Natural Gas Company Rights Agreement, is hereby
                  incorporated by reference to Exhibit 1 to the Current Report on Form 8-K
                  filed on January 23, 1996 


</TABLE>
 
                                       75
<PAGE>   78
 
ITEM 14.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Continued)
 
<TABLE>
<CAPTION>
EXHIBITS (Continued)
-----------------------------------------------------------------------------------------------
 SEC
Exhibit
Number                                   Description of Exhibit
-----------------------------------------------------------------------------------------------
<C>      <S>      <C>                                     <C>
 (10)    Material Contracts:
         The following exhibits are filed with this Form 10-K by being incorporated by
         reference to their filing in the Company's Forms 10-K for previous years. The
         following table indicates for each of such exhibits the Form 10-K, File No. 1-3196,
         where such exhibit was filed. Exhibits not included in this table are filed herewith
         or incorporated by reference to another source as indicated below.

                  Form 10-K Exhibit Number                     Reporting Year of Form 10-K
                  (10A), (10B), (10C), (10E), (10G)                       1987
                  (10H), (10 I)                                           1989
                  (10F), (10J), (10L)                                     1994

         (10A)    Form of Split Dollar Insurance Agreement between Consolidated Natural Gas
                  Company and certain employees and Directors

         (10B)    Form of Supplemental Death Benefit Payment Agreement between Consolidated
                  Natural Gas Company and certain employees and Directors

         (10C)    Consolidated Natural Gas Company Supplemental Retirement Benefit Plan

         (10D)    System Supplemental Retirement Plan for Certain Management Employees of
                  Consolidated Natural Gas Company and Its Participating Subsidiaries, as
                  amended December 12, 1995, is filed herewith

         (10E)    Form of agreement between Consolidated Natural Gas Company and non-employee
                  Directors for deferral of payment of retainer and attendance fees, effective
                  before 1987

         (10F)    Deferred Compensation Plan for Directors of Consolidated Natural Gas Company,
                  effective for years beginning with 1987, as amended December 13, 1994

         (10G)    Consolidated Natural Gas Company Cash Incentive Bonus Deferral Plan

         (10H)    Form of Change of Control Employment Agreement between Consolidated Natural
                  Gas Company and certain employees

         (10I)    Form of Change of Control Salary Continuation Agreement between Consolidated
                  Natural Gas Company and certain employees

         (10J)    Description of Consolidated Natural Gas Company Annual Executive Incentive
                  Program, as amended December 13, 1994

         (10K)    Unfunded Supplemental Benefit Plan for Employees of Consolidated Natural Gas
                  Company and Its Participating Subsidiaries Who Are Not Represented by a
                  Recognized Union, as amended December 12, 1995, is filed herewith

         (10L)    Description of Consolidated Natural Gas Company Non-Employee Directors'
                  Restricted Stock Plan
</TABLE>
 
                                       76
<PAGE>   79
 
ITEM 14.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Concluded)
 
<TABLE>
<CAPTION>
EXHIBITS (Concluded)
-----------------------------------------------------------------------------------------------
 SEC
Exhibit
Number                                   Description of Exhibit
-----------------------------------------------------------------------------------------------
<C>      <S>      <C>
         (10M)    Description of Consolidated Natural Gas Company 1995 Employee Stock Incentive
                  Plan, is filed herewith

         (10N)    Form of Change of Control Employment Agreement between Consolidated Natural
                  Gas Company and certain employees dated December 12, 1995, is filed herewith

 (11)    Statement re Computation of Per Share Earnings:
         Computations of Earnings Per Share of Common Stock, Primary Earnings Per Share, and
         Fully Diluted Earnings Per Share of Consolidated Natural Gas Company and Subsidiaries
         for the years ended December 31, 1993 through 1995, are filed herewith

 (12)    Statement re Computation of Ratios:
         Ratio of Earnings to Fixed Charges of Consolidated Natural Gas Company and
         Subsidiaries for the calendar years 1991-1995, inclusive, are filed herewith

 (21)    Subsidiaries of the Registrant:
         Subsidiaries of Consolidated Natural Gas Company, is filed herewith

 (23)    Consents of Experts and Counsel:
         (23A)    Report of Ralph E. Davis Associates, Inc., independent geologists, dated
                  February 12, 1996, and consent letter authorizing the filing of such report
                  as an exhibit to Consolidated Natural Gas Company's Form 10-K for the year
                  ended December 31, 1995, are filed herewith

         (23B)    Consent of Price Waterhouse LLP--included as part of this ITEM 14

 (27)    Financial Data Schedule, is filed herewith
-----------------------------------------------------------------------------------------------
</TABLE>
 
                                       77
<PAGE>   80
 
                                   SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
 
                                              CONSOLIDATED NATURAL GAS COMPANY
 
                                            ------------------------------------
                                                        (Registrant)
 
                                                  GEORGE A. DAVIDSON, JR.
                                            By
                                               ----------------------------- 
                                                 (George A. Davidson, Jr.)
                                                   Chairman of the Board
March 27, 1996                                  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 the registrant and
in the capacities indicated on March 27, 1996.

<TABLE>
<S>                                                                <C>
             GEORGE A. DAVIDSON, JR.                                                  PAUL E. LEGO
-------------------------------------------------                  -------------------------------------------------
            (George A. Davidson, Jr.)                                                (Paul E. Lego)
              Chairman of the Board                                                     Director
           and Chief Executive Officer,
                   and Director                                                   MARGARET A. MCKENNA
                                                                   -------------------------------------------------
                  D. M. WESTFALL                                                 (Margaret A. McKenna)
-------------------------------------------------                                       Director
                 (D. M. Westfall)
              Senior Vice President                                                 STEVEN A. MINTER
           and Chief Financial Officer                             -------------------------------------------------
                                                                                   (Steven A. Minter)
                  S. R. MCGREEVY                                                        Director
-------------------------------------------------
                 (S. R. McGreevy)                                                  WALTER R. PEIRSON
            Vice President, Accounting                             -------------------------------------------------
              and Financial Control                                               (Walter R. Peirson)
                                                                                        Director
             WILLIAM S. BARRACK, JR.
-------------------------------------------------                                  RICHARD P. SIMMONS
            (William S. Barrack, Jr.)                              -------------------------------------------------
                     Director                                                     (Richard P. Simmons)
                                                                                        Director
                  J. W. CONNOLLY
-------------------------------------------------                                      LOIS WYSE
                 (J. W. Connolly)                                  -------------------------------------------------
                     Director                                                         (Lois Wyse)
                                                                                        Director
                  RAY J. GROVES
-------------------------------------------------
                 (Ray J. Groves)
                     Director
</TABLE>

                                                                 78
<PAGE>   81
APPENDIX TO FORM 10-K

The following graphic material which appeared in the paper format version of
the document is omitted from this electronic format document:

Map of Principal Facilities at December 31, 1995 (Page 18)

This map shows the primary operating areas of Consolidated Natural Gas Company
in Ohio, Pennsylvania, Virginia and West Virginia.  The map shows the principal
cities served at retail including Cleveland, Akron, Youngstown, Canton, Warren,
Lima, Ashtabula and Marietta in Ohio; Pittsburgh (a portion), Altoona and
Johnstown in Pennsylvania; Norfolk, Newport News and Williamsburg in Virginia;
and Clarksburg and Parkersburg in West Virginia.  The map also shows the
general location of Consolidated's pipelines and joint venture pipelines,
including gas delivery connections with customers and gas receipt or delivery
connections with other pipelines.  Also shown on the map are the general
locations of certain compressor facilities and underground storage fields.

Map of Exploration and Production Areas at December 31, 1995 (Page 19)

This United States map shows the general areas in which Consolidated conducts
its exploration and production activities.  These areas include:  the Gulf of
Mexico, offshore Louisiana and Texas; the Gulf Coast Basin; Permian Basin;
Anadarko Basin; Arkoma Basin; Black Warrior Basin; San Juan Basin; Williston
Basin; Michigan Basin; Rocky Mountain Basins and the Appalachian Region.  Also
shown is the general location of Consolidated's Canadian exploration and
production properties in Alberta, Canada.
<PAGE>   82
<TABLE>
<CAPTION>
                                 EXHIBIT INDEX
---------------------------------------------------------------------------------------------
 SEC
Exhibit
Number                                      Description of Exhibit
---------------------------------------------------------------------------------------------
<C>      <S>      <C>
  (3)    Articles of Incorporation and By-Laws:
         (3A)     Certificate of Incorporation of Consolidated Natural Gas Company, restated
                  October 4, 1990 (incorporated by reference to Exhibit A-1 to the
                  Application-Declaration of Consolidated Natural Gas Company on Form U-1,
                  File No. 70-7811)

         (3B)     By-Laws of Consolidated Natural Gas Company, last amended March 1, 1993
                  (incorporated by reference to Exhibit (3B) filed with Consolidated Natural
                  Gas Company's Form 10-K for the year ended December 31, 1992, File No.
                  1-3196)

  (4)    Instruments Defining the Rights of Security Holders, Including Indentures:
         (4A)     (1) Indentures of Consolidated Natural Gas Company:
                  Indentures of Consolidated Natural Gas Company are incorporated by
                  reference to previously filed material as indicated on the list filed
                  herewith
                  (2) Note Purchase Agreement of Virginia Natural Gas:
                  Note Purchase Agreement dated as of January 1, 1989, between Virginia
                  Natural Gas, Inc. and the Aid Association for Lutherans relating to
                  $20,000,000 principal amount of 9.94% Senior Notes, Series A, due January
                  1, 1999 (incorporated by reference to Exhibit B-1 to the
                  Application-Declaration of Consolidated Natural Gas Company on Form U-1,
                  File No. 70-7667)

         (4B)     Section 203 of the Delaware General Corporation Law, "Business Combinations
                  With Interested Stockholders," effective February 2, 1988 (incorporated by
                  reference to Exhibit (4B) filed with Consolidated Natural Gas Company's
                  Form 10-K for the year ended December 31, 1987, File No. 1-3196)
                  Other portions of the Delaware General Corporation Law affecting security
                  holder rights are considered routine and are not filed hereunder

          (4C)    Description of Consolidated Natural Gas Company Rights Agreement, is hereby
                  incorporated by reference to Exhibit 1 to the Current Report on Form 8-K
                  filed on January 23, 1996 
</TABLE>
<PAGE>   83
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
 SEC
Exhibit
Number                                   Description of Exhibit
-----------------------------------------------------------------------------------------------
<C>      <S>      <C>
 (10)    Material Contracts:
         The following exhibits are filed with this Form 10-K by being incorporated by
         reference to their filing in the Company's Forms 10-K for previous years. The
         following table indicates for each of such exhibits the Form 10-K, File No. 1-3196,
         where such exhibit was filed. Exhibits not included in this table are filed herewith
         or incorporated by reference to another source as indicated below.

                  Form 10-K Exhibit Number                     Reporting Year of Form 10-K
                  (10A), (10B), (10C), (10E), (10G)                       1987
                  (10H), (10 I)                                           1989
                  (10F), (10J), (10L)                                     1994

         (10A)    Form of Split Dollar Insurance Agreement between Consolidated Natural Gas
                  Company and certain employees and Directors

         (10B)    Form of Supplemental Death Benefit Payment Agreement between Consolidated
                  Natural Gas Company and certain employees and Directors

         (10C)    Consolidated Natural Gas Company Supplemental Retirement Benefit Plan

         (10D)    System Supplemental Retirement Plan for Certain Management Employees of
                  Consolidated Natural Gas Company and Its Participating Subsidiaries, as
                  amended December 12, 1995, is filed herewith

         (10E)    Form of agreement between Consolidated Natural Gas Company and non-employee
                  Directors for deferral of payment of retainer and attendance fees, effective
                  before 1987

         (10F)    Deferred Compensation Plan for Directors of Consolidated Natural Gas Company,
                  effective for years beginning with 1987, as amended December 13, 1994

         (10G)    Consolidated Natural Gas Company Cash Incentive Bonus Deferral Plan

         (10H)    Form of Change of Control Employment Agreement between Consolidated Natural
                  Gas Company and certain employees

         (10I)    Form of Change of Control Salary Continuation Agreement between Consolidated
                  Natural Gas Company and certain employees

         (10J)    Description of Consolidated Natural Gas Company Annual Executive Incentive
                  Program, as amended December 13, 1994

         (10K)    Unfunded Supplemental Benefit Plan for Employees of Consolidated Natural Gas
                  Company and Its Participating Subsidiaries Who Are Not Represented by a
                  Recognized Union, as amended December 12, 1995, is filed herewith

         (10L)    Description of Consolidated Natural Gas Company Non-Employee Directors'
                  Restricted Stock Plan
</TABLE>
<PAGE>   84
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
 SEC
Exhibit
Number                                   Description of Exhibit
-----------------------------------------------------------------------------------------------
<C>      <S>      <C>
         (10M)    Description of Consolidated Natural Gas Company 1995 Employee Stock Incentive
                  Plan, is filed herewith

         (10N)    Form of Change of Control Employment Agreement between Consolidated Natural
                  Gas Company and certain employees dated December 12, 1995, is filed herewith

 (11)    Statement re Computation of Per Share Earnings:
         Computations of Earnings Per Share of Common Stock, Primary Earnings Per Share, and
         Fully Diluted Earnings Per Share of Consolidated Natural Gas Company and Subsidiaries
         for the years ended December 31, 1993 through 1995, are filed herewith

 (12)    Statement re Computation of Ratios:
         Ratio of Earnings to Fixed Charges of Consolidated Natural Gas Company and
         Subsidiaries for the calendar years 1991-1995, inclusive, are filed herewith

 (21)    Subsidiaries of the Registrant:
         Subsidiaries of Consolidated Natural Gas Company, is filed herewith

 (23)    Consents of Experts and Counsel:
         (23A)    Report of Ralph E. Davis Associates, Inc., independent geologists, dated
                  February 12, 1996, and consent letter authorizing the filing of such report
                  as an exhibit to Consolidated Natural Gas Company's Form 10-K for the year
                  ended December 31, 1995, are filed herewith

         (23B)    Consent of Price Waterhouse LLP--included as part of ITEM 14

 (27)    Financial Data Schedule, is filed herewith
-----------------------------------------------------------------------------------------------
</TABLE>