CONSOLIDATED NATURAL GAS CO - 10-K Annual Report

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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, 1993

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:

Common Stock: Registered:

$2.75 Par Value New York Stock Exchange

Debentures:
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

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 $4,270,115,002 as of January 31, 1994. It was assumed
in this calculation that the registrant's affiliates are all of its directors
and/or officers, and they beneficially owned 109,953 shares of voting stock at
that date.

Number of shares of Common Stock, $2.75 Par Value, outstanding at January 31,
1994: 92,938,540.

The registrant's "Notice of Annual Meeting and Proxy Statement, 1994" is hereby
incorporated by reference into Part III of this Form 10-K.

CONSOLIDATED NATURAL GAS COMPANY
FORM 10-K ANNUAL REPORT
For the Year Ended December 31, 1993

TABLE OF CONTENTS
PART I Page

ITEM 1. BUSINESS
The Company and its Subsidiaries . . . . . . 1
Governmental Regulation . . . . . . . . . 3
Capital Expenditures . . . . . . . . . . 3
Competitive Conditions . . . . . . . . . 4
Gas Supply . . . . . . . . . . . . . 7
Gas Sales and Transportation . . . . . . . 11
Gas Sales, Supply and Transportation Statistics . 13
Market Expansion . . . . . . . . . . . 14
Rate Matters. . . . . . . . . . . . . 16
Executive Officers of the Company. . . . . . 18
ITEM 2. PROPERTIES
General Information on Facilities. . . . . . 19
Map - Principal Facilities . . . . . . . . 20
Map - Exploration and Production Areas . . . . 21
Gas and Oil Producing Activities . . . . . . 22
ITEM 3. LEGAL PROCEEDINGS. . . . . . . . . . . . 25
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 25

PART II

ITEM 5. MARKET FOR THE COMPANY'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS . . . . . . . . . . . 25
ITEM 6. SELECTED FINANCIAL DATA. . . . . . . . . . 26
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS. . . . . . 27
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA . . . 47
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE. . . . . . 88

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY. . 88
ITEM 11. EXECUTIVE COMPENSATION . . . . . . . . . . 88
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT . . . . . . . . . . . . . . 88
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS . . 88

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
ON FORM 8-K. . . . . . . . . . . . . . 88

SIGNATURES . . . . . . . . . . . . . . . . . 92

CONSOLIDATED NATURAL GAS COMPANY
FORM 10-K ANNUAL REPORT
For the Year Ended December 31, 1993

PART I
ITEM 1. BUSINESS

THE COMPANY AND ITS SUBSIDIARIES

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. 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 ("Consolidated" or the
"Company") at December 31, 1993, are listed below. The subsidiary companies
are engaged in, and their total operating revenues are derived from, all phases
of the natural gas business -- exploration, production, purchasing, gathering,
transmission, storage, distribution, and marketing, together with by-product
operations (see Note 2 to the Financial Statements, page 57). At December 31,
1993, Consolidated had 7,625 regular employees.

_______________________________________________________________________________
__________________

State of
Name of Company
Incorporation
_______________________________________________________________________________
__________________

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
The River Gas Company ("River Gas"). . . . . . . . . . . . . .
West Virginia
CNG Producing Company ("CNG Producing") . . . . . . . . . . . .
Delaware
CNG Energy Company ("CNG Energy") . . . . . . . . . . . . . .
Delaware
CNG Gas Services Corporation ("CNG Gas 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
_______________________________________________________________________________
__________________

The principal cities served at retail by Consolidated's gas distribution
subsidiaries (East Ohio Gas, River 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, 1993, Consolidated served at
retail approximately 1,777,000 residential, commercial and industrial gas sales
customers in Ohio, Pennsylvania, Virginia and West Virginia. With 98 percent
of their residential and commercial customers using gas for space heating,
variations in weather conditions can materially affect the volume of gas
delivered by the distribution subsidiaries of the Company.

1

ITEM 1. BUSINESS (Continued)

CNG Transmission is the Company's interstate gas transmission subsidiary. CNG
Transmission operates a regional interstate pipeline system serving each of the
Company's distribution subsidiaries, and nonaffiliated utility and end-user
customers in 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 several years. Under the most recent regulatory initiative, 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. CNG Transmission implemented FERC Order 636 on October 1, 1993
(see "FERC Order 636," page 39) 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. Because a substantial part of its gas deliveries is ultimately used
by space-heating customers, variations in weather conditions can materially
affect the volume of gas transported and stored by CNG Transmission.

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 formed to construct, own and
operate 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 Consolidated's exploration and production subsidiary. Gas and
oil exploration and production activities are conducted by this subsidiary
primarily in the Gulf of Mexico, the southern and western United States, the
Appalachian region, and in Canada. In addition, CNG Producing participates in
coalbed methane projects throughout the United States.

CNG Energy develops new business opportunities for the Company in energy-re-
lated markets. It invests in and develops independent power producer projects
and conducts a gas liquids business.

CNG Gas Services (formerly CNG Trading Company) is Consolidated's unregulated
gas marketing subsidiary. CNG Gas Services markets a portion of Company-owned
production and, during 1993, began offering the equivalent of the "bundled"
services previously provided by CNG Transmission. CNG Gas Services 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 in the post-Order 636 environment.

CNG Storage was formed to engage 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 has ended its
involvement in LNG operations 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 the Company's proprietary research activities.
Amounts spent on research activities in the calendar years 1991 through 1993 by
all of the subsidiary companies were not material.

CNG Coal owns Consolidated's coal reserves and a related plant site. The
Company's recoverable raw coal reserves are approximately 615 million tons, as
estimated by John T. Boyd Company, Mining and Geological Engineers. Most of
these coal reserves are located in Greene County, Pennsylvania, principally in
the Sewickley and Pittsburgh coal seams. The Company has various options under
review with respect to these properties.

2

ITEM 1. BUSINESS (Continued)

Service Company is a subsidiary service company, authorized by the Securities
and Exchange Commission ("SEC") under the Public Utility Holding Company Act of
1935 ("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 and its subsidiaries are subject to regulation by the SEC pursuant
to the PUHCA.

CNG Transmission and Consolidated LNG are "natural-gas companies" subject to
the Natural Gas Act of 1938, as amended. Their sales in interstate commerce
for resale and interstate transportation and storage activities are regulated
under such Act and are made in accordance with gas tariffs and service
agreements on file with the FERC. The distribution subsidiaries of the Company
are subject to regulation by the respective utility commissions in the states
within which they operate.

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 Natural Gas Policy Act of 1978 ("NGPA"), established maximum
lawful wellhead prices for various categories of natural gas and provided for
decontrol of certain natural gas prices at various times. However, the
Decontrol Act of 1989 effected the total decontrol of natural gas wellhead
prices on January 1, 1993. Another statute, 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, author-
izes 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.

Consolidated is subject to the provisions of various federal laws dealing with
the protection of the environment. 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 "Environmental Matters" on page
42, and to Notes 15 and 16 to the Financial Statements, for additional
information on environmental-related matters. (See "LEGAL PROCEEDINGS," page
25.)

CAPITAL EXPENDITURES

Consolidated's current capital budget for 1994 is estimated at $439.6 million,
a 28 percent increase over the $342.6 million spent in 1993. The 1994 budget
reflects increased projected expenditures for all of the Company's major
business components.

Expenditures for the exploration and production operations are estimated to be
$153.0 million in 1994, up from $110.7 million in 1993. The higher amount in
1994 includes funds for development of the "Popeye" deep-water project in the
Gulf of Mexico, and provides for an increased level of exploratory drilling.
Distribution operations spending in 1994 is expected to be $141.8 million,
compared with $115.4 million in 1993. The increased level of spending will
allow for continued growth, as well as improvements in the gas distribution
system and related facilities. Although the multi-year expansion program of
the transmission operations is substantially complete, the Company continues to
make

3

ITEM 1. BUSINESS (Continued)

enhancements to its pipeline network to better serve customers. Transmission
expenditures in 1994 are budgeted at $124.4 million, up from $113.4 million
spent in 1993. The 1994 capital budget also includes $17.9 million in
connection with CNG Energy's investment in the Lakewood cogeneration project in
New Jersey.

CNG Transmission and certain of the Company's distribution subsidiaries are
subject to the Federal Clean Air Act and the Federal Clean Air Act Amendments
of 1990 ("1990 amendments") which added significantly to the existing
requirements established by the Federal Clean Air Act. These subsidiaries
operate compressor stations that are covered by the new nitrogen oxide emission
standard established as a result of the 1990 amendments. The Company will have
until May 31, 1995, to comply with the emission standard. The Company expects
that compliance will require significant capital expenditures to modify the
compressor engines along the Company's pipeline system. However, the actual
cost of compliance will be dependent upon the requirements imposed by the
environmental agencies of the states in which the compressor stations are
located. Based on the Company's preliminary estimates and analyses,
approximately $46 million of capital expenditures may be required over the next
two years. The actual amounts required to comply with the 1990 amendments are
expected to be recoverable through future regulatory proceedings.

Consolidated's capital budget will be reviewed during the year in light of
market conditions and is subject to revision. (See "Capital Spending," page
44.)

COMPETITIVE CONDITIONS

Various regulatory and market trends have combined to increase competition for
Consolidated 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; competition from local producers and other sellers and
brokers of gas for the retail and wholesale markets; 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

During 1993, the final portion of the FERC's plan to restructure the interstate
natural gas pipeline industry was set in motion as pipeline companies began
implementing the provisions of FERC Order 636. 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. Order 636 required interstate
pipelines, including CNG Transmission, to "unbundle" their services into
separate sales, transportation and storage services and to offer and price such
services separately. 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. As the result of
Order 636, each pipeline company was required to revise its customer contracts
and service tariffs. The Order allows pipelines to recover 100 percent of all
prudently incurred costs resulting from the transition to the new rules. CNG
Transmission implemented FERC Order 636 on October 1, 1993 (see "FERC Order
636," page 39) 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.

4

ITEM 1. BUSINESS (Continued)

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. The distribution
subsidiaries have, for the most part, however, 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, these companies now bear all the
responsibilities and risks for arranging the acquisition, delivery and storage
of their own gas supplies. As a result of previous FERC initiatives,
Consolidated's distribution subsidiaries have been managing a part of their own
gas supplies for the last several 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 Company's distribution and transmission operations as
well as storage capacity acquired will be even more important factors in gas
supply management.

Also, as a result of the restructuring, gas producers throughout the industry,
including CNG Producing, now face 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.

DISTRIBUTION

Consolidated's 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 Company's 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 Consolidated's transmission system and storage
facilities, and has afforded additional opportunities for growth in both gas
sales and transportation, especially in the power generation markets.

The Clean Air Act may also provide opportunities for increased throughput in
the Company's distribution markets. Consolidated is promoting the use of
natural gas as a means for industrial customers and electric generators to
reduce emissions. The 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. Consolidated is participating in various programs to demonstrate the
advantages and environmental benefits of natural gas powered vehicles.

The Company's distribution markets continue to be competitive. 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. 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

5

ITEM 1. BUSINESS (Continued)

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.
Consolidated has responded to this competitive environment by offering an
expanded range of services to its customers. The Company's distribution
subsidiaries now routinely provide a variety of firm and interruptible
services, 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. 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 several years. Beginning with open access
transportation and culminating with the significant service restructuring
required by FERC Order 636, the role of the Company's 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 Mid-West 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. This
expansion has occurred in many directions, with particular emphasis on
Northeast and East Coast markets. CNG Transmission's large underground storage
capacity and the location of its 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.

On October 1, 1993, CNG Transmission implemented Order 636 in accordance with
the terms of a comprehensive settlement reached with customers and others (see
"FERC Order 636," page 39). CNG Transmission's 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 are expected to help offset the impact of lower gas sales.
Consolidated continues to provide the equivalent of bundled services through
its unregulated marketing subsidiary, CNG Gas Services. This company offers a
range of gas sales, transportation, storage and other service options that can
be arranged separately or in various combinations to meet the individual needs
of customers.

EXPLORATION AND PRODUCTION

Consolidated's 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,
Consolidated competes with a large number of companies ranging in size from
large international oil companies with extensive financial resources to small,
cash flow-driven independent producers.

6

ITEM 1. BUSINESS (Continued)

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
also highly competitive with price being the most significant factor. When the
economics warrant, Consolidated 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 implementation by pipeline
companies of the FERC's Order 636 could impact the deliverability of gas
produced due to increased competition for limited downstream pipeline
transportation capacity. In response to the unbundling of sales services
previously offered by pipelines, CNG Producing and CNG Gas Services have taken
actions to expand and diversify the Company's customer base. These
subsidiaries continue to 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 Consolidated's exploration and production operations.

GAS SUPPLY

GENERAL INFORMATION

Consolidated'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 some commercial
customers now purchase a large portion of their gas supplies from producers,
marketers, or on the spot market, and contract with the Company's 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. In addition, the implementation of FERC Order
636 by CNG Transmission in effect removed that subsidiary from its merchant
role thereby eliminating its need to purchase gas for resale. The former
merchant service contracted for by wholesale customers was converted to
transportation and storage services in 1993. Since CNG Transmission no longer
provides traditional sales service, its former sales customers, including the
Company's distribution subsidiaries, now have the responsibility and risk for
obtaining their own gas supplies.

Consolidated's available gas supply in 1993 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
contracts, Company-owned gas reserves, and assuming the future availability of
spot market gas, the Company believes that supplies will be available to meet
requirements for several years. Gas supply statistics for the past five years
are on page 13.

7

ITEM 1. BUSINESS (Continued)

GAS PURCHASED

Purchased gas volumes were 485.2 billion cubic feet in 1993, representing 75
percent of the Company's total 1993 gas supply of 648.2 billion cubic feet.
Spot market gas purchases were 392.2 billion cubic feet, or about 61 percent of
the total 1993 supply. Volumes purchased under contracts with producers,
primarily in the Appalachian area, totaled 79.4 billion cubic feet, or 12
percent of the 1993 supply. Purchases from pipeline companies were 13.6
billion cubic feet in 1993, or 2 percent of the 1993 supply.

In response to the regulatory and market changes over the past several years,
the Company has been converting its long-term gas purchase contracts with
interstate pipelines to firm transport contracts. As a result of these
contract conversions, gas volumes purchased from the pipeline companies have
declined and have been replaced, in large part, with contracts directly with
producers and lower-cost spot market gas. As pipelines implemented FERC Order
636 in 1993, the Company's remaining long-term purchase contracts with these
companies were converted to firm transportation.

While spot market gas supplies have historically been obtained at lower prices,
the availability of spot market gas supplies to distribution companies can be
severely impacted by sudden 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 Company's distribution
subsidiaries anticipate purchasing a larger portion of their gas supplies
directly from producers on a firm basis. Although the volume of gas obtained
on the spot market by the distribution subsidiaries is expected to decline,
spot market gas will continue to be an important part of the Company's supply
mix, particularly for CNG Gas Services.

Gas purchased from producers and on the spot market is delivered to the
subsidiaries using their firm transport capacity on interstate pipelines. At
December 31, 1993, the subsidiaries had 425 billion cubic feet of firm
transport capacity on upstream pipelines, yielding deliveries of up to 1,174
million cubic feet a day. These upstream pipelines include Tennessee Gas
Pipeline Company, Panhandle Eastern Pipe Line Company, Texas Eastern
Transmission Corporation, ANR Pipeline Company, Texas Gas Transmission
Corporation, Transcontinental Gas Pipe Line Corporation and Columbia Gas
Transmission Corporation.

GAS STORAGE

Consolidated's vast 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 billion cubic feet. The Company's share of
the total capacity is about 669 billion cubic feet. 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 710 billion cubic feet of the total storage capacity
and owns 503 billion cubic feet of the Company's capacity. CNG Transmission
utilizes a large portion of its turnable capacity to provide approximately 252
billion cubic feet 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.

8

ITEM 1. BUSINESS (Continued)

Two of the Company's distribution subsidiaries, East Ohio Gas and Peoples
Natural Gas, own and operate the remaining 166 billion cubic feet of storage
capacity. In addition to owning their own storage, these companies, as well as
most of the Company's other subsidiaries have ready access to a part 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 will be an
important element in the effective management of both gas supply and pipeline
transport capacity.

Consolidated 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.

GAS AND OIL PRODUCING ACTIVITIES

Over the past several years, Consolidated's exploration and production
operations have been affected by the generally adverse conditions in the
industry. The effects of persistent warm weather, the lingering gas oversupply
situation, and low gas and oil wellhead prices have all contributed to a
difficult operating environment. Also during this time, the level of capital
spending for exploration and development activities was reduced as a greater
proportion of capital resources was devoted to the Company's pipeline expansion
projects. As a result of these conditions, Consolidated reduced its
exploration and production activities. During 1992, natural gas market
conditions improved as spot market prices rebounded after falling to a low of
about $1.00 per thousand cubic feet in February 1992. The improving conditions
continued in 1993 as gas prices firmed generally above $2.00. Conditions in
oil markets, however, worsened during 1993.

Consolidated's gas wellhead prices in 1993 averaged $2.24 a thousand cubic
feet, up from $2.05 in 1992. Gas wellhead prices were strong throughout most
of 1993 and were above 1992 levels for most of the year. Consolidated'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-sensitive contracts, Consolidated's prices
generally follow industry trends. Consolidated's average oil wellhead price in
1993 was $15.66 per barrel, down from $18.15 in 1992. Oil prices were weak
through most of the year and fell sharply near year-end, reflecting the trend
in world prices.

The Company's total gas production in 1993 was 129.5 billion cubic feet, up
from 128.0 billion cubic feet produced in 1992. Oil production was 3.9 million
barrels, down 13 percent from 4.5 million barrels in 1992. Although gas
production was up slightly in 1993, it was limited somewhat due to reduced
deliverability at certain properties and the sale of selected properties in the
Appalachian area. The lower oil production in 1993 was attributable primarily
to normal production declines at older properties.

In light of the difficult industry conditions of the past few years,
Consolidated has restructured its exploration and production operations and
refocused its efforts into selected geographic areas. These efforts are
currently directed to moderate- and low-risk prospects, principally in the Gulf
of Mexico.

The Company has also taken steps to address the recent declines in short-term
deliverability. During 1993, the Company completed a series of well workovers
and a compression project that had been postponed in prior years due to the low
level of gas prices. While these efforts have helped restore short-term
deliverability, any significant increases will be dependent primarily on future
exploratory successes.

9

ITEM 1. BUSINESS (Continued)

During 1993, Consolidated participated in the drilling of 65 gross wells (22
net), compared with 106 gross wells (68 net) drilled in 1992. The following
table sets forth 1993 drilling activity by region:
_______________________________________________________________________________
Gross Wells Drilled
Exploratory Development
_______________________________________________________________________________

Onshore (Southwest and West). . . . . . . 7 32
Gulf of Mexico . . . . . . . . . . . 15 7
Canada . . . . . . . . . . . . . . - 4
__ __
Total. . . . . . . . . . . . . . 22 43
== ==
_______________________________________________________________________________

Of the total 65 wells in which the Company participated during 1993, 46 were
successful, a 71 percent success rate. Of the 22 exploratory wells drilled, 6
were successful.

Although Consolidated's drilling program was reduced in 1993, it resulted in a
number of successful completions. An exploratory well drilled at South Marsh
Island Block 154 in the Gulf of Mexico resulted in a natural gas and oil
discovery. Consolidated is the operator of this property and owns a 50 percent
working interest. The South Marsh Island 154 discovery was brought onto
production in just seven months by using a refitted production platform from
one of the Company's depleted fields. Another significant success in the Gulf
in 1993 was at the West Cameron Block 76 field. After doubling the Company's
interest in the field to 40 percent in 1992, a new development well resulted in
the largest single addition to Consolidated's reserves in 1993. Other
successes offshore included wells drilled at Vermilion Block 255 and at West
Cameron Block 293.

A large part of the Company's development drilling in 1993 occurred at the Sand
Dunes field located in the New Mexico portion of the Permian Basin.
Consolidated participated in the drilling of 26 development wells in this area
and has added approximately 900 barrels of oil a day to the Company's
production. Consolidated's working interest in these wells averaged about 26
percent. Development drilling is expected to continue in this field during
1994.

Also during 1994, development will continue at "Popeye," a deep-water natural
gas discovery in the Green Canyon area of the Gulf of Mexico. Consolidated
entered into an agreement in 1992 with Shell Offshore, Inc., under which the
Company acquired half of Shell's 75 percent interest in this property. In
return, Consolidated will pay some $60 million for development of the field.
Other participants in the joint venture are Mobil Oil Exploration and Producing
Southeast and BP Exploration Inc. Participation in the Popeye project is
providing Consolidated access to a new technology and the experience necessary
to better evaluate future deep-water opportunities.

Despite difficult industry conditions, Consolidated remains committed to its
exploration and production operations. The Company plans to increase its
exploration and production spending by 38 percent in 1994 to $153.0 million.
The anticipated expenditures include funds for the development of Popeye and
provide for an increased level of exploratory drilling.

10

ITEM 1. BUSINESS (Continued)

Consolidated did not participate in drilling activity in the Appalachian Basin
during 1993, and there is no drilling planned for this area in 1994. In the
past, gas from this area commanded a higher price because of its location in
proximity to major gas markets. However, as a result of industry changes and
revised rate structures, pipeline companies can transport gas to these markets
at low commodity rates that negate somewhat the location premium associated
with these reserves. The Company expects to continue production from these
properties and plans to maintain its strong acreage position in the Appalachian
Basin. Drilling activity can be resumed with very short lead times if market
and economic conditions warrant. Selected Appalachian properties were sold
during 1993, but the acreage and reserves were not material.

Total Company-owned proved gas reserves at year-end were 960 billion cubic
feet, down from 998 billion cubic feet at the end of 1992. Proved oil reserves
were 27.9 million barrels, compared with 29.5 million barrels in 1992. Because
of the low level of drilling activity, new reserves added during 1993 were not
sufficient to replace the volumes of gas produced during the year. (See
"Company-Owned Reserves," page 22.)

Consolidated was the successful bidder on nine leases offered in the federal
government's Gulf of Mexico lease sales in 1993, acquiring five blocks off
Louisiana and four blocks off Texas. At year-end 1993, Consolidated held 2.6
million net acres of exploration and production properties, down from 2.7
million at year-end 1992. The Company's lease holdings include about 1.8
million net acres in the Appalachian area, 386,000 in the offshore Gulf of
Mexico, and 495,700 in the inland areas of the Southwest, Gulf Coast and West.

The Company will continue to review its property inventory during 1994, and
sales of selected properties are possible depending on economic conditions.
Included in the properties which may be sold is Consolidated's 21 percent
interest in heavy oil properties in Alberta, Canada. Proved reserves
associated with the Canadian properties approximated 1.1 billion cubic feet of
gas and 5.7 million barrels of oil at December 31, 1993. On an energy-
equivalent basis, these reserves represent about 3 percent of Consolidated's
total proved reserves at that date.

GAS SALES AND TRANSPORTATION

Total gas sales in 1993 were 604 billion cubic feet, up 35 percent from the 449
billion cubic feet sold in 1992. Transportation volumes were 587 billion cubic
feet in 1993, a 4 percent decrease from the 613 billion cubic feet transported
in 1992. (Five-year statistics are on page 13.)

GAS SALES CUSTOMERS

At December 31, 1993, the Company's distribution subsidiaries served almost 1.7
million residential customers, over 118,000 commercial customers and more than
1,800 industrial customers in Ohio, Pennsylvania, Virginia and West Virginia.
_______________________________________________________________________________
Residential
Customers Total and Commercial Industrial Wholesale Nonregulated
_______________________________________________________________________________
December 31,
1993 1,777,320 1,774,922 1,851 31 516
1992 1,759,428 1,757,139 1,838 32 419
1991 1,738,098 1,735,803 1,849 31 415
1990 1,718,016 1,715,824 1,787 32 373
1989 1,543,845 1,541,680 1,750 36 379
_______________________________________________________________________________

11

ITEM 1. BUSINESS (Continued)

RESIDENTIAL AND COMMERCIAL SALES

Sales of gas to residential customers in 1993 were 212 billion cubic feet, up 4
billion cubic feet from 1992, while sales to commercial customers were 73
billion cubic feet, virtually unchanged compared with 1992. Residential gas
sales volumes increased as slightly colder weather in 1993 resulted in higher
gas usage by space-heating customers. The weather in the Company's retail
service areas in 1993 was 2 percent colder than in 1992 but still warmer than
normal. Also contributing to the increase was the net addition of about 17,800
residential and commercial customers, including about 7,800 at Virginia Natural
Gas.

INDUSTRIAL SALES

Industrial sales in 1993 were 12 billion cubic feet, about the same as in 1992.
Due to both availability and price, many of the Company's industrial customers
now buy gas directly from producers, from marketers, or on the spot market, and
contract with the subsidiary companies for transportation service. The total
gas deliveries (sales and transportation) to industrial customers was 128
billion cubic feet in 1993, compared with 127 billion cubic feet in 1992.

WHOLESALE SALES

Total wholesale sales were 81 billion cubic feet in 1993, up from 21 billion
cubic feet in 1992. The increase in sales volumes was due to the sale by CNG
Transmission of approximately 58 billion cubic feet of gas from storage
inventory in anticipation of the transition to restructured services under FERC
Order 636. These sales, which were made primarily to customers outside the
Company's traditional Northern Market area at reduced prices under alternative
FERC-approved tariff schedules, increased available capacity to provide future
storage service and reduced certain transition costs under Order 636.

NONREGULATED SALES

Nonregulated gas sales in 1993 were 226 billion cubic feet, up from 134 billion
cubic feet in 1992. Sales of Company-produced gas to nonaffiliates was 88
billion cubic feet, compared with 109 billion cubic feet in 1992. Gas sales by
CNG Gas Services were 100 billion cubic feet in 1993, its first year of
operations. Volumes related to gas brokering activity were 38 billion cubic
feet in 1993, up from 25 billion cubic feet in 1992.

GAS TRANSPORTATION

Total transportation volumes in 1993 amounted to 587 billion cubic feet, down
from 613 billion cubic feet in 1992. Increased wholesale sales volumes, due
largely to CNG Transmission's sales from storage inventory prior to its
transition to FERC Order 636, was the principal reason for the lower
transportation volumes in 1993. In the fourth quarter of 1993, following CNG
Transmission's implementation of Order 636, gas transportation volumes
increased due primarily to volumes transported for customers in the Northern
Market area and Virginia. Total volumes transported by the distribution
subsidiaries for commercial, industrial and off-system customers were up 2
billion cubic feet over 1992.

12

ITEM 1. BUSINESS (Continued)

GAS SALES, SUPPLY AND TRANSPORTATION STATISTICS
(Excludes affiliated transactions)

_______________________________________________________________________________
___________________________________
Years Ended December 31, 1993 1992
1991 1990 1989
_______________________________________________________________________________
___________________________________

GAS SALES REVENUES (MILLIONS)
Regulated
Residential and commercial. . . . . . . $1,595.1 $1,428.7
$1,373.1 $1,361.0 $1,457.1
Industrial . . . . . . . . . . . . 55.4 50.0
46.0 64.2 67.2
Wholesale - Northern Market . . . . . . 230.0 125.7
311.6 375.2 475.4
- Off-system . . . . . . . . 192.7 65.1
115.2 153.7 131.0
Nonregulated . . . . . . . . . . . . 541.8 282.0
237.0 280.2 256.7
________ ________
________ ________ ________
Total . . . . . . . . . . . . $2,615.0 $1,951.5
$2,082.9 $2,234.3 $2,387.4
======== ========
======== ======== ========

AVERAGE SALES RATES PER MCF
Regulated
Residential and commercial. . . . . . . $ 5.60 $ 5.09
$ 5.25 $ 5.39 $ 5.23
Industrial . . . . . . . . . . . . 4.43 4.00
4.09 4.22 4.35
Wholesale - Northern Market . . . . . . * *
4.69 4.97 4.56
- Off-system . . . . . . . . 3.49 *
4.03 4.34 4.07
Nonregulated . . . . . . . . . . . . 2.40 2.10
2.01 2.27 2.19
Weighted average. . . . . . . . . $ 4.33 $ 4.35
$ 4.29 $ 4.45 $ 4.36
======== ========
======== ======== ========

GAS REQUIREMENTS (BCF)
Regulated gas sales
Residential and commercial. . . . . . . 285.0 280.7
261.7 252.5 278.8
Industrial . . . . . . . . . . . . 12.5 12.5
11.2 15.2 15.5
Wholesale - Northern Market . . . . . . 25.5 9.4
66.4 75.5 104.2
- Off-system . . . . . . . . 55.2 11.8
28.6 35.4 32.2
Nonregulated gas sales. . . . . . . . . 226.0 134.4
118.1 123.4 117.1
________ ________
________ ________ ________
Total sales . . . . . . . . . . 604.2 448.8
486.0 502.0 547.8
Used and unaccounted for . . . . . . . . 44.0 51.7
34.5 44.7 28.9
________ ________
________ ________ ________
Total requirements . . . . . . . . 648.2 500.5
520.5 546.7 576.7
======== ========
======== ======== ========

GAS SUPPLY (BCF)
Purchased gas. . . . . . . . . . . . 485.2 370.6
377.2 434.4 416.5
Storage (input) withdrawal . . . . . . . 33.5 1.9
10.5 (34.8) 12.7
Gas produced
Appalachian area . . . . . . . . . . 29.4 33.1
35.3 43.5 45.9
Gulf region. . . . . . . . . . . . 81.6 78.9
84.2 89.4 90.0
Other areas. . . . . . . . . . . . 18.5 16.0
13.3 14.2 11.6
________ ________
________ ________ ________
Total produced . . . . . . . . . 129.5 128.0
132.8 147.1 147.5
________ ________
________ ________ ________
Total supply . . . . . . . . . . 648.2 500.5
520.5 546.7 576.7
======== ========
======== ======== ========

PURCHASED GAS COSTS (MILLIONS)** . . . . . $1,358.2 $1,132.1
$1,093.6 $1,440.7 $1,328.7
======== ========
======== ======== ========

AVERAGE PURCHASE RATES PER MCF** . . . . . $ 2.80 $ 3.05
$ 2.90 $ 3.32 $ 3.19
======== ========
======== ======== ========

GAS TRANSPORTATION
Revenues (Millions). . . . . . . . . . $ 222.5 $ 201.0
$ 154.9 $ 147.5 $ 128.6
======== ========
======== ======== ========

Gas Transported (Bcf) . . . . . . . . . 587.5 613.1
446.7 377.8 388.6
======== ========
======== ======== ========
_______________________________________________________________________________
___________________________________

* Demand charges and low sales volumes produce an average rate which is not
meaningful.
** Includes transportation charges.

13

ITEM 1. BUSINESS (Continued)

MARKET EXPANSION

For the past several years Consolidated has pursued a broad program designed to
expand its interstate pipeline system and extend its marketing territory.
Consolidated'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. Consolidated 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,
Consolidated 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.

Consolidated is also developing and promoting additional uses for natural gas.
These technologies provide opportunities for the use of natural gas in markets
that are not sensitive to the weather. The more stringent air quality
standards required under the Federal Clean Air Act and the various provisions
of the Energy Policy Act of 1992 should help advance the development and use of
these and other technologies.

TRANSMISSION EXPANSION

During 1993, the final phase of the expansion of CNG Transmission's interstate
pipeline between Lebanon, Ohio, and its storage field at Leidy, Pennsylvania,
was completed. This $240 million project was the primary, and largest,
component of the Company's $600 million multi-year transmission expansion
program. The new pipeline and additional compressor facilities added to this
main line will be used to transport up to 370 million cubic feet of gas a day
on behalf of Transcontinental Gas Pipe Line Corporation and customers of ANR
Pipeline Company for ultimate delivery to East Coast markets.

Also in 1993, CNG Transmission expanded its market area further to the south.
On November 1, 1993, CNG Transmission began providing a combination of storage
and transportation service to Public Service Company of North Carolina, Inc.
Under this 20-year contract, CNG Transmission is providing about 30 million
cubic feet of gas a day. Since the Company's pipeline system does not extend
into North Carolina, CNG Transmission delivers the gas to Transcontinental Gas
Pipe Line Corporation at Nokesville in northern Virginia, and Transcontinental
delivers the gas by displacement in North Carolina.

With the transmission construction program essentially complete, the Company is
now pursuing new growth opportunities available for its expanded pipeline
system. In March 1994, Consolidated announced plans to create a new gas market
center that will offer service at points along CNG Transmission's pipeline
system to utilities, interstate pipelines, large end-users and marketers
throughout the Mid-Atlantic and the East Coast. This market center is being
developed by CNG Transmission and Texaco's Sabine Pipe Line Company. The hub
is expected to begin operating in 1994 offering services such as intra-hub
transfers, parking and wheeling, together with a new service designed to reduce
the administrative burden associated with buying and selling gas. These
services are designed to help minimize transaction costs and give buyers and
sellers more options for trading. The CNG/Sabine Center is expected to further
increase throughput and also offer new marketing opportunities for CNG Gas
Services.

14

ITEM 1. BUSINESS (Continued)

TECHNOLOGY-BASED MARKETS

During 1993, Consolidated continued its involvement with a number of relatively
new gas burning technologies. These applications provide opportunities to
improve customer efficiency while promoting the use of natural gas in market
sectors that are not sensitive to the weather or economic downturn. The future
advancement of such technologies also appears promising as business entities
strive to comply with provisions of the Federal Clean Air Act. This
legislation applies strict anti-pollution standards to factories, fleet and
mass transit vehicles, and to 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. This Act 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.

With regard to these market expansion efforts, Consolidated has participated
extensively in developing and marketing a technology called "cofiring," in
which a small amount of gas is burned along with coal in an electric utility or
industrial boiler. Cofiring has resulted in improved boiler efficiency and has
reduced certain emissions which are responsible for acid rain. Consolidated is
also promoting "reburn," which is a more advanced version of cofiring. Under
this technique, natural gas is injected into the upper part of a boiler,
creating a fuel-rich zone where nitrogen oxide is transformed into harmless
nitrogen.

Consolidated 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 turning to NGVs for both fuel cost efficiencies and as
a way 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 individual
vehicles. However, beginning in 1997, the Clean Air Act could require 22 of
the country's most polluted regions to convert a portion of their fleet
vehicles to natural gas. Consolidated 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.

15

ITEM 1. BUSINESS (Continued)

RATE MATTERS (See Note 3 to the Financial Statements, page 57.)

The Company's average unit selling price of gas to its customers was $4.33 per
thousand cubic feet in 1993, compared with $4.35 in 1992 and $4.29 in 1991.
Average sales prices in 1993 were higher for all retail categories and for
Company-produced gas. However, CNG Transmission's sales from storage inventory
had a significant influence on the overall average unit selling price since
such sales were made at lower rates under alternative FERC-approved tariff
schedules in anticipation of the implementation of Order 636. The higher
average selling price in 1992 compared with 1991 reflects the upward industry
trend in gas wellhead prices experienced in 1992.

The Company's utility 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 1993 and to date.

CNG TRANSMISSION

In April 1992, the FERC issued Order 636, a comprehensive set of regulations
designed to encourage competition and continue the significant restructuring of
the interstate natural gas pipeline industry that the FERC first set in motion
with its Order 436. As the result of Order 636, each pipeline company was
required to revise its customer contracts and service tariffs. On November 2,
1992, CNG Transmission filed with the FERC a revised service tariff complying
with the provisions of the Order. On March 31, 1993 (as amended June 15,
1993), CNG Transmission filed a comprehensive stipulation and agreement
("Settlement") which revised substantially the November 2, 1992, filing. On
July 16, 1993, the FERC issued an order approving CNG Transmission's amended
Settlement, subject to certain modifications, clarifications and
justifications. Following a series of Commission orders relating to these
matters, CNG Transmission implemented Order 636 in accordance with the terms of
the Settlement (Docket No. RS92-14) on October 1, 1993. (See "FERC Order 636,"
page 39.)

On December 30, 1993, CNG Transmission filed a general rate filing with the
FERC requesting an annual revenue increase of $106.6 million. CNG Transmission
requested an 11.78 percent overall rate of return and a 14.00 percent return on
equity. The rate increase request is intended to cover higher operating costs,
increased plant investment, and the recovery of $9.2 million in transition
costs related to stranded facilities because of Order 636. The increase is
expected to become effective, after the suspension period, on July 1, 1994,
subject to refund.

VIRGINIA NATURAL GAS

On June 22, 1993, the Virginia State Corporation Commission approved a $10.4
million annual revenue increase for Virginia Natural Gas. The new rates were
effective retroactive to September 4, 1992, and reflect an 11.75 percent return
on equity. In its April 1992 filing, Virginia Natural Gas had requested a
$14.1 million annual increase in revenues and a 12.25 percent return on equity.

16

ITEM 1. BUSINESS (Continued)

PEOPLES NATURAL GAS

On October 28, 1993, Peoples Natural Gas filed with the Pennsylvania Public
Utility Commission for a $28.4 million increase in base rates. In its filing,
Peoples Natural Gas requested a 10.00 percent overall rate of return and a
12.25 percent return on equity. The rate increase request is intended to cover
higher operating expenses. If approved, the new rates would become effective
on August 6, 1994. Peoples Natural Gas also filed to recover, over four years,
$20.1 million in estimated transition costs related to FERC Order 636.

HOPE GAS

On October 29, 1993, the Public Service Commission of West Virginia granted
Hope Gas an indicated $1.9 million annual revenue increase effective
November 1, 1993. The approved rates reflect an 8.78 percent overall rate of
return and a 10.20 percent return on equity. In its March 1993 filing, Hope
Gas had requested an $8.2 million increase in revenues and an estimated 12.30
percent return on equity. On November 8, 1993, Hope Gas filed a petition for
rehearing in the case.

EAST OHIO GAS

On January 18, 1994, East Ohio Gas filed with the Public Utilities Commission
of Ohio ("PUCO") for a $99.1 million increase in base rates. East Ohio Gas is
seeking a 10.95 percent overall rate of return and a 12.50 percent return on
equity. The rate increase request is intended to cover higher operating costs
and increases in plant investment. The filing also reflects the proposed
merger of River Gas into East Ohio Gas and the combining of the operations and
service areas of the two subsidiary companies. A decision by the PUCO is
expected in October 1994. In addition, East Ohio Gas is negotiating with
customers and the PUCO staff as to the future recovery of transition costs to
be incurred under FERC Order 636.

17

ITEM 1. BUSINESS (Concluded)

EXECUTIVE OFFICERS OF THE COMPANY (Note 1)
_______________________________________________________________________________
Name, Age and Business Experience
Position (Note 2) During Past Five Years
_______________________________________________________________________________

George A. Davidson, Jr. (55) Mr. Davidson was elected to his present
Chairman of the Board and position on May 19, 1987, and has been a
Chief Executive Officer, Director since October 1985.
and Director

Lester D. Johnson (62) Mr. Johnson was elected to his present
Executive Vice President and position on March 1, 1992, and has been
Chief Financial Officer, a Director since May 1992. He served as
and Director Senior Vice President and Chief
Financial Officer from January 1986 to
March 1992.

David E. Weatherwax (63) Mr. Weatherwax was elected to his
Senior Vice President, present position on January 1, 1993. He
Administration served as Senior Vice President,
Administration and General Counsel from
March 1992 to January 1993 and Senior
Vice President and General Counsel from
July 1987 to March 1992.

Stephen E. Williams (45) Mr. Williams was elected to his present
Senior Vice President and position on January 1, 1993. He served
General Counsel as Associate General Counsel from
September 1992 to January 1993. From
April 1987 to September 1992, he served
as General Counsel and Secretary of CNG
Transmission.

David J. Dzuricky (42) Mr. Dzuricky was elected to his present
Vice President and Treasurer position on August 1, 1993. He served
as Vice President and Treasurer of
Virginia Natural Gas from July 1992 to
August 1993, and as its Vice President,
Treasurer and Controller from January
1991 to July 1992, and Vice President,
Treasurer, Secretary and Controller from
June 1990 to January 1991. From January
1988 to June 1990, he served as
Treasurer of CNG Transmission.

Stephen R. McGreevy (43) Mr. McGreevy was elected to his present
Vice President, Accounting position on March 1, 1993. He served as
and Financial Control Controller from January 1986 to March
1993.

Laura J. McKeown (35) Ms. McKeown was elected to her present
Secretary position on May 16, 1989. She served as
Assistant Secretary from August 1987 to
May 1989.

Thomas F. Garbe (41) Mr. Garbe was elected to his present
Controller position on March 1, 1993. He served as
Senior Assistant Controller from May
1991 to March 1993 and Assistant
Controller from January 1986 to May
1991.
_______________________________________________________________________________

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.

18

ITEM 2. PROPERTIES

GENERAL INFORMATION ON FACILITIES (Maps are on pages 20 and 21.)

The total gross investment of the Company and its subsidiaries in property,
plant and equipment was $7.3 billion at December 31, 1993. The largest portion
of this investment (62%) is in facilities located in the Appalachian area.
Another significant portion (22%) is located in the Gulf of Mexico.

Of the $7.3 billion investment, $3.3 billion is in production and gathering
systems, of which 56 percent is invested in the Gulf of Mexico and the Gulf
coast and 29 percent in the Appalachian area. The Company's production
subsidiary, CNG Producing, accounts for $2.7 billion of the $3.3 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 7,188 miles of gathering lines
which are located almost entirely within the Appalachian area.

The Company's investment in its gas distribution network includes 28,165 miles
of pipe, exclusive of service pipe, the cost of which represents 61% of the
$1.5 billion invested in the total function.

The Company's storage operation, the largest in the industry, consists of 26
storage fields, 331,848 acres of operated leaseholds, 2,032 storage wells and
828 miles of pipe. The investment in storage properties is $644 million,
including $124 million of cushion gas stored.

Of the $1.5 billion invested in transmission facilities, 69% represents the
cost of 7,402 miles of pipe required to move large volumes of gas throughout
the Company's operating area.

The Company has 111 compressor stations with 452,157 installed compressor
horsepower. Some of the stations are used interchangeably for several
functions.

The Company's investment in its fully integrated 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 9.1 Bcf on January 18, 1994. The
system peak day sendout in 1993 was 7.9 Bcf on February 24.

19

Map of Principal Facilities at December 31, 1993
(GRAPHIC MATERIAL OMITTED)
20

Map of Exploration and Production Areas at December 31, 1993
(GRAPHIC MATERIAL OMITTED)
21

ITEM 2. PROPERTIES (Continued)

GAS AND OIL PRODUCING ACTIVITIES (See Note 17(A) to the Financial Statements,
page 72.)

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, 1991
through 1993, follow:

_______________________________________________________________________________
________________________
December 31, 1993 1992
1991
_______________________________________________________________________________
________________________

Proved Total Proved
Total Proved Total
Developed Proved Developed
Proved Developed Proved
_______________________________________________________________________________
________________________

Gas Reserves (Bcf)
Non-cost-of-service . . . . . . 761 885 794
918 855 918
Cost-of-service . . . . . . . 75 75 80
80 87 87
______ ______ ______
______ ______ ______
Total . . . . . . . . . . 836 960 874
998 942 1,005
====== ====== ======
====== ====== ======

Oil Reserves (000 Bbls)
Non-cost-of-service . . . . . . 21,936 27,596 27,449
29,238 30,070 31,014
Cost-of-service . . . . . . . 287 287 283
283 313 313
______ ______ ______
______ ______ ______
Total . . . . . . . . . . 22,223 27,883 27,732
29,521 30,383 31,327
====== ====== ======
====== ====== ======
_______________________________________________________________________________
________________________

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, 1992, as well as those which will be reported at
December 31, 1993, are not reconcilable with Company-owned reserves because
they are calculated on an operated basis and include working interest reserves
of all parties.

QUANTITIES OF GAS AND OIL PRODUCED

Net quantities (net before royalty) of gas and oil produced during each of the
last three years follow:
_______________________________________________________________________________
Years Ended December 31, 1993 1992 1991
_______________________________________________________________________________

Gas Production (Bcf)
Non-cost-of-service . . . . . . . . . 124 121 126
Cost-of-service . . . . . . . . . . 6 7 7
_____ _____ _____
Total . . . . . . . . . . . . . 130 128 133
===== ===== =====

Oil Production (000 Bbls)
Non-cost-of-service . . . . . . . . . 3,907 4,508 5,246
Cost-of-service . . . . . . . . . . 29 31 33
_____ _____ _____
Total . . . . . . . . . . . . . 3,936 4,539 5,279
===== ===== =====
_______________________________________________________________________________

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 1991 through 1993 was $1.96,
$2.05 and $2.24, respectively. The respective average sales prices for oil
were $19.53, $18.15 and $15.66 per barrel. The average production (lifting)
cost per Mcf equivalent of non-cost-of-service gas and oil produced during the
years 1991 through 1993 was $.37, $.37 and $.33, respectively.

22

ITEM 2. PROPERTIES (Continued)

PRODUCTIVE WELLS

The number of productive gas and oil wells in which the subsidiary companies
have an interest at December 31, 1993, follow:
_______________________________________________________________________________
Gas Wells Oil Wells
Gross Net Gross Net
_______________________________________________________________________________

Non-cost-of-service* . . . . . . . . 5,601 4,715 853 407
Cost-of-service . . . . . . . . . . 2,181 1,811 3 3
_____ _____ ___ ___
Total. . . . . . . . . . . . . 7,782 6,526 856 410
===== ===== === ===
_______________________________________________________________________________
* Includes 46 gross (12 net) multiple completion gas wells and 5 gross (2 net)
multiple completion oil wells.

ACREAGE

The following table sets forth the gross and net developed and undeveloped
acreage of the subsidiary companies at December 31, 1993:
_______________________________________________________________________________
Developed Acreage Undeveloped Acreage
Gross Net Gross Net
_______________________________________________________________________________

Non-cost-of-service. . . . 1,621,117 1,227,844 1,309,456 933,323
Cost-of-service . . . . . 440,912 439,179 42,124 37,775
_________ _________ _________ _________
Total. . . . . . . . 2,062,029 1,667,023 1,351,580 971,098
========= ========= ========= ========
_______________________________________________________________________________

Approximately 32% 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):
_______________________________________________________________________________
Exploratory Development Total
Productive Dry Productive* Dry Productive Dry
_______________________________________________________________________________

Years Ended December 31,
1993 . . . . . . . 2 6 13 1 15 7
1992 . . . . . . . 1 3 54 10 55 13
1991 . . . . . . . 3 7 39 7 42 14
_______________________________________________________________________________
* Includes Canadian completions: 1993 - 1 well, 1992 - 0 wells and 1991 - 4
wells.

As of December 31, 1993, 4 gross (2 net) non-cost-of-service wells were in
process of drilling, including wells temporarily suspended. As of December 31,
1993, Consolidated was engaged in waterflood projects in Oklahoma and Texas and
an enhanced oil recovery program in Alberta, Canada.

23

ITEM 2. PROPERTIES (Concluded)

GAS PURCHASE CONTRACT RESERVES (AT DECEMBER 31, 1993) AND AVAILABILITY OF
SUPPLY (CALENDAR YEAR 1994)

Gas purchase reserves under contract with independent producers in the
Appalachian area total 960 billion cubic feet at December 31, 1993. In
addition, at December 31, 1993, Consolidated had gas supply contracts with
various other producers and marketers with contract lengths ranging from a few
months to ten years. The volume of gas available to Consolidated under these
supply contracts totals 458 billion cubic feet if all volumes are requested.
These gas purchase contract reserve and gas supply contract volume amounts are
as contained in the February 15, 1994 report of Ralph E. Davis Associates, Inc.
Of the total 960 billion cubic feet under contract from Appalachian producers,
the volume of gas expected to be purchased in 1994 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 458
billion cubic feet available under contract from other producers and marketers,
approximately 229 billion cubic feet of gas will be available to Consolidated
in 1994, assuming all volumes are requested. During 1993, Consolidated
converted its remaining gas purchase contracts with interstate pipeline
companies to firm transportation contracts, and no gas purchases from pipeline
companies are expected in 1994.

The Company anticipates that substantial volumes of gas will be available for
purchase during 1994 on the spot market. Due to the nature of spot market
transactions, the volumes of such gas available to Consolidated in 1994 cannot
be reasonably estimated. However, for the calendar year 1994, Consolidated
expects its distribution subsidiaries to have approximately 409 billion cubic
feet of firm transport capacity available on upstream pipelines and 57 billion
cubic feet of storage capacity available to meet their customer requirements.

The volumes expected to be available from Company-owned wells in 1994 amount to
139 billion cubic feet of gas and 4,124 thousand barrels of oil. Included in
these amounts are 133 billion cubic feet of gas and 4,095 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.

24

ITEM 3. LEGAL PROCEEDINGS

As previously reported, in June 1993, CNG Transmission received a Notice of
Violation from the Pennsylvania Department of Environmental Resources ("DER")
alleging violations of the Pennsylvania Clean Streams Law and three Earth
Disturbance Permits issued thereunder. CNG Transmission was assessed a penalty
of $405,450 by the DER, which was paid in December 1993. CNG Transmission is
seeking recovery of a substantial portion of the penalty paid in this matter
from third party contractors under contractual indemnification provisions.

Reference is made to "Environmental Matters," page 42, and to Notes 15 and 16
to the Financial Statements, page 70, for additional environmental-related
information.

Reference is made to "Rate Matters," page 16, 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 17(C) to the Financial Statements, page
77, and reference is made thereto.
25

ITEM 6. SELECTED FINANCIAL DATA

_______________________________________________________________________________
________________________________________
SUMMARY OF FINANCIAL DATA (Thousand $) 1993 1992
1991 1990 1989
_______________________________________________________________________________
________________________________________

EARNINGS
Gas sales . . . . . . . . . . . . . $ 2,615,036 $ 1,951,545
$ 2,082,927 $ 2,234,347 $ 2,387,401
Other operating revenues . . . . . . . . 569,049 569,305
524,079 480,524 414,497
Total operating revenues . . . . . . . 3,184,085 2,520,850
2,607,006 2,714,871 2,801,898
Purchased gas and other products . . . . . 1,665,338 1,059,177
1,237,227 1,344,588 1,446,904
Operation and maintenance, depreciation . . . 980,350 950,093
924,242 911,407 872,909
Total taxes . . . . . . . . . . . . 280,959 237,938
215,476 210,582 228,281
Operating income . . . . . . . . . . 257,438 273,642
230,061 248,294 253,804
Interest expense. . . . . . . . . . . 90,260 100,764
111,255 117,034 100,119
Interest during construction. . . . . . . 10,785 17,331
23,426 24,161 22,260
Other income (net) . . . . . . . . . . 10,531 4,749
26,381 8,349 5,829
Income before change in accounting principle . 188,494 194,958
168,613 163,770 181,774
Cumulative effect of applying SFAS No. 109 . . 17,422 -
- - - -
Net income . . . . . . . . . . . . 205,916 194,958
168,613 163,770 181,774
Per share of common stock
Income before change in accounting principle. $2.03 $2.19
$1.94 $1.91 $2.20
Cumulative effect of applying SFAS No. 109 . .19 -
- - - -
Net income . . . . . . . . . . . . $2.22 $2.19
$1.94 $1.91 $2.20
Average common shares outstanding . . . . . 92,808,156 89,127,805
86,836,920 85,683,172 82,492,459
Return on average stockholders' equity . . . 9.6% 9.7%
9.0% 9.3% 11.0%
Times fixed charges earned . . . . . . . 3.95 3.41
2.86 2.73 3.30
_______________________________________________________________________________
________________________________________
DIVIDENDS - CASH
Paid per common share . . . . . . . . . $1.92 $1.90
$1.88 $1.84 $1.76
Payout ratio . . . . . . . . . . . 86.5% 86.8%
96.9% 96.3% 80.0%
Declared per common share. . . . . . . . $1.925 $1.905
$1.885 $1.85 $1.78
_______________________________________________________________________________
________________________________________
ASSETS
Total assets . . . . . . . . . . . . $ 5,409,586 $ 5,155,662
$ 4,992,602 $ 5,006,038 $ 4,605,296
Property, plant and equipment
Total investment . . . . . . . . . . 7,346,028 7,087,102
6,749,165 6,433,527 5,910,198
Accumulated depreciation . . . . . . . 3,429,760 3,212,202
3,010,776 2,820,771 2,556,771
Capital expenditures and acquisitions. . . . 342,569 441,518
493,033 559,514 630,826
_______________________________________________________________________________
________________________________________
CAPITAL STRUCTURE
Total common stockholders' equity . . . . . $ 2,176,432 $ 2,132,838
$ 1,889,783 $ 1,844,594 $ 1,671,898
Long-term debt . . . . . . . . . . . 1,158,648 1,111,956
1,159,123 1,128,513 890,626
____________ ____________
____________ ____________ ____________
Total capitalization. . . . . . . . . $ 3,335,080 $ 3,244,794
$ 3,048,906 $ 2,973,107 $ 2,562,524
============ ============
============ ============ ============
Long-term debt ratio . . . . . . . . . 34.7% 34.3%
38.0% 38.0% 34.8%
Shares of common stock outstanding at year-end. 92,933,828 92,557,017
87,321,917 86,327,073 82,525,561
Common stockholders' equity per share . . . $23.42 $23.04
$21.64 $21.37 $20.26
_______________________________________________________________________________
________________________________________

26

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

RESULTS OF OPERATIONS

NET INCOME

Net income in 1993 was $206 million, a 6 percent increase over the $195 million
earned in 1992. On a per share basis, 1993 net income was $2.22 compared with
$2.19 in 1992. The earnings per share amounts reported for 1993 and 1992
reflect the sale of 4.6 million shares of common stock in September 1992. Net
income in 1991 was $169 million, or $1.94 a share.

Colder weather, higher prices for natural gas production, increased gas
deliveries resulting from pipeline expansion projects, higher by-product
revenues and reduced interest expense were major factors for the earnings
improvement in 1993. While weather in Consolidated's retail service areas was
colder than in 1992, it was still warmer than normal for the fourth consecutive
year. Normal weather represents a measure of temperature experienced over a 30-
year period. Normal weather in 1993 would have added about $.06 a share to the
$2.22 a share reported.

Earnings in both 1993 and 1992 included the positive impact of deferred tax
benefits. In 1993, 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 are reported as a separate component of net income as
the cumulative effect of the accounting change. By contrast, deferred tax
benefits recognized in 1992 under the previously applicable accounting standard
reduced income tax expense in that year by $13.0 million, or $.15 a share.

The positive factors in 1993 were offset in part, however, 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.

Colder weather compared with 1991, the continued expansion of the Company's
transmission operations, increased gas storage service revenues, and higher
wellhead prices for gas were major factors for the earnings improvement in 1992
compared with 1991. Although weather in Consolidated's retail service areas
was colder than in 1991, the weather was warmer than normal. If weather in the
retail service areas had been normal in 1992, earnings would have been $.16 a
share higher than the $2.19 reported. Gas wellhead prices fell sharply early
in 1992, but recovered and strengthened as gas demand increased due to cold
spring weather and concerns over possible supply shortages following Hurricane
Andrew. The increase in average gas wellhead prices for the year was offset to
a large extent by lower gas and oil production and lower average oil wellhead
prices. The net income comparison of the two years was also affected by the
recognition in 1991 of interest revenues related to the settlement of federal
income tax issues from prior years.

In 1991, warm weather depressed the level of earnings throughout all three of
Consolidated's major business components. If weather in Consolidated's retail
service areas had been normal in 1991, earnings would have been $.33 a share
higher than the $1.94 reported for that year. Reduced gas demand, declining
gas field prices and the curtailment of gas production resulted in sharply
lower exploration and production earnings. Higher other income, including
interest revenues related to the settlement of federal income tax issues from
prior years, was also a significant factor contributing to earnings in 1991.

27

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

INCOME FROM OPERATIONS

Operating income for Consolidated's business components for the last three
years is shown in the following table. Operating income is presented on an
after-tax basis consistent with the Statement of Income where income taxes are
classified as an operating expense.

Effective January 1, 1993, Consolidated's CNG Trading Company subsidiary was
renamed CNG Gas Services Corporation. In addition to continuing its
predecessor's role of marketing a portion of Company-owned production, CNG Gas
Services arranges gas supplies, transportation, storage and related services
for customers. The demand for these services was created by Federal Energy
Regulatory Commission (FERC) Order 636, which has restructured the natural gas
marketplace. As a result of this new role, amounts pertaining to the
operations of CNG Gas Services are included in the caption "Other" in the
following table, as well as in the other tables presented in this discussion
and analysis. Amounts applicable to CNG Trading for 1992 and 1991 remain in
the exploration and production component.

______________________________________________________________________________
OPERATING INCOME 1993 1992 1991
______________________________________________________________________________
(In Millions)
Distribution . . . . . . . . . . . $122.5 $130.0 $110.7
Transmission . . . . . . . . . . . 98.0 84.0 79.9
Exploration and production . . . . . . 35.3 50.7 37.6
Other* . . . . . . . . . . . . . .3 8.7 1.1
Intercompany eliminations and adjustments . 1.3 .2 .8
______ ______ ______
Total . . . . . . . . . . . . $257.4 $273.6 $230.1
====== ====== ======
______________________________________________________________________________
* Includes CNG Gas Services, CNG Energy, Consolidated System LNG, CNG Research,
CNG Coal and Parent companies.

Due to the regulated nature of the distribution and transmission components of
Consolidated'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 operation. 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.

DISTRIBUTION

"Distribution" represents the results of Consolidated's six retail gas
distribution subsidiaries, including their minor gas and oil production
activities. These subsidiaries are subject to price regulation by their
respective state utility commissions.

Operating income for the gas distribution operations in 1993 was down $7.5
million, or 6 percent, from 1992. Higher costs of operations and the increase
during 1993 in the federal corporate income tax rate more than offset the
impact of slightly colder weather and a minor increase in throughput in 1993.
Overall, weather in Consolidated's retail service areas was 2 percent colder
than in 1992, but 1 percent warmer than normal. The colder weather, the net
addition of about 17,800 residential and commercial gas sales customers 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 results.
To help mitigate the effect of rising non-gas operating costs and to enable a
return to be earned on new facilities placed in service, Consolidated's two
largest distribution subsidiaries, The East Ohio Gas Company and The Peoples
Natural Gas Company, have filed for general rate increases. However,
resolution of these proceedings is not expected until the latter part of 1994.

28

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

Operating income in 1992 increased $19.3 million, or 17 percent, over 1991 due
in large part to colder weather in the 1992 period. Overall, weather in
Consolidated's retail service areas was 12 percent colder than in 1991, but 3
percent warmer than normal. However, due to the seasonality of their
operations, the overall deviation from normal weather in 1992 was not entirely
indicative of the weather's financial impact on the distribution operations.
Specifically, in the five principal heating months of 1992, weather in
Consolidated's retail service areas was 3 percent colder than in 1991 and 8
percent warmer than normal. The net addition of some 21,000 residential and
commercial gas sales customers also contributed to the improved operating
results. Further, the distribution operations benefited from a full year of
general rate increases granted to two subsidiaries during 1991, and the impact
of general rate increases placed into effect by two subsidiaries in the latter
part of 1992.

Exceptionally warm weather in 1991 had a particularly noticeable impact on gas
distribution operations, limiting the level of gas deliveries and holding
operating income in that year to a relatively low level. Weather in
Consolidated's retail service areas was 14 percent warmer than normal in 1991.

TRANSMISSION

"Transmission" includes the results of the gas transmission, storage, by-
product and certain other activities of CNG Transmission Corporation and the
activities of CNG Storage Service Company. Gas and oil production activities
of CNG Transmission are included in exploration and production operations. The
interstate gas transmission and related operations of CNG Transmission are
regulated by the FERC.

Operating income of the gas transmission operations in 1993 increased $14.0
million, or 17 percent, over 1992. The improvement was due partly to 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 also contributed to the increased operating income in 1993. The
operating results of the transmission operations in the year were also
favorably affected, but to a lesser extent, by sales of gas from storage
inventory and certain other steps taken to facilitate the transition to FERC
Order 636.

Operating income in 1992 was up $4.1 million, or 5 percent, over 1991. The
expansion of transportation service to both new customers and existing
wholesale customers and end-users on the East Coast, including power generation
customers, and increased demand by traditional Northern Market customers were
the most significant factors affecting the 1992 results. Colder weather and
increased storage service revenues also contributed to the improvement. The
increased transportation to utilities and end-users in the Northeast and along
the East Coast was the result of the completion of several of the Company's
pipeline expansion projects. The impact of these positive factors was
partially offset by higher operating costs in 1992.

The operating results in 1991 were influenced to a large extent by the
implementation of restructured service agreements in connection with the
settlement with the FERC of CNG Transmission's 1988 general rate case. The
impact of this settlement included a significant increase in storage service
revenues resulting from customers' increased access to CNG Transmission's
storage facilities and increased gas transportation volumes due to the
conversion by some customers from sales service to firm transportation.

29

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

EXPLORATION AND PRODUCTION

"Exploration and production" includes the results of CNG Producing Company, the
gas and oil production activities of CNG Transmission, and, in 1992 and 1991,
the results of CNG Trading Company.

The adjustment to deferred income tax balances to reflect the increase in the
federal corporate income tax rate had a significant impact on the operating
income of Consolidated's exploration and production operations in 1993.
Operating income of the exploration and production operations was $35.3 million
in 1993, down from $50.7 million in 1992. These amounts are on an after-tax
basis consistent with the Statement of Income where income taxes are classified
as an operating expense. However, as a result of the implementation of SFAS
No. 109 and the increase in the federal tax rate, the comparison of 1993
operating results with 1992 is significantly distorted. Deferred tax benefits
resulting from the adoption of SFAS No. 109 in 1993 are included separately as
a component of net income below the operating income line as part of the
cumulative effect of the accounting change. In addition, operating income in
1993 for the exploration and production operations was reduced by $8.8 million
due to the tax rate increase, including the adjustment to existing deferred tax
balances required by SFAS No. 109 and the current year effect of applying the
new higher rate retroactive to January 1, 1993. By contrast, operating income
in 1992 reflected an increase for certain deferred tax benefits that had been
recognized under the previous accounting standard. On a pretax basis,
operating income of the exploration and production operations was $47.3 million
in 1993, up $8.5 million, or 22 percent, compared with $38.8 million in 1992.
Positive factors affecting operating results in 1993 included higher wellhead
prices for natural gas and slightly higher gas production. Consolidated's gas
wellhead prices in 1993 averaged $2.24 per thousand cubic feet, a 9 percent
increase from 1992. The positive factors were offset by higher income taxes,
lower oil prices and production, and lower margins on the brokering of gas.
The average oil wellhead price realized of $15.66 per barrel was 14 percent
below 1992 levels.

Operating income in 1992 rose $13.1 million, an increase of 35 percent over
1991. The impacts of higher gas wellhead prices and reduced operation and
maintenance expense were offset somewhat by lower gas and oil production and
lower wellhead oil prices. Gas wellhead prices followed industry trends,
falling early in the year but recovering and strengthening as the year
progressed. Consolidated's gas wellhead prices in 1992 averaged $2.05 per
thousand cubic feet, up 5 percent from 1991. The decline in operation and
maintenance expense resulted from cost containment programs and, to a lesser
extent, the lower gas and oil production levels. Overall, gas production for
1992 was down 4 percent and oil production was down 14 percent.

The generally adverse conditions in natural gas markets nationwide -- including
excess supply, reduced demand due to the warmer-than-normal weather and the
dramatically low level of wellhead prices -- were the primary reasons for the
relatively low operating income in 1991. The average gas wellhead price
realized was $1.96 per thousand cubic feet in 1991, the lowest level on an
annual basis in over 10 years. The shut-in of certain high-deliverability
offshore gas production for a portion of the year, and lower oil production and
prices also contributed to the low 1991 operating income.

30

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

UTILITY GAS SALES AND TRANSPORTATION VOLUMES

During 1993, the final portion of the FERC's plan to restructure the interstate
natural gas pipeline industry was set in motion as pipeline companies began
implementating the provisions of FERC Order 636. 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 other large-volume end-users, including former pipeline
sales customers, now bear all the responsibilities and risks for arranging the
procurement and delivery of their gas supplies.

On October 1, 1993, CNG Transmission implemented Order 636 with the required
"unbundled" services and new rate structure. Since Consolidated's utility
subsidiaries had already been managing a part of their own gas supplies, the
transition to the more competitive environment under Order 636 did not have a
significant impact on their operations. In addition, Consolidated, through its
CNG Gas Services subsidiary, continues to offer the equivalent of bundled
services previously provided by CNG Transmission.

The gas sales and transportation volumes of the distribution and transmission
operations for the last three years are presented in the following table.
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. "Normal weather," as the term is used in the gas industry,
represents the mean of temperatures experienced, measured in terms of degree
days, over a 30-year period. A degree day is a measure of the coldness of the
weather based on the extent to which the daily mean temperature falls below 65
degrees Fahrenheit. The 30-year average, which is calculated by a federal
agency, is updated approximately every 10 years. For Consolidated, "normal
weather" is determined using the weighted average of the normal degree days
experienced in its retail service territories.

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. The distribution and transmission operations provide gas
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.

_______________________________________________________________________________
UTILITY GAS SALES AND TRANSPORTATION 1993 1992 1991
_______________________________________________________________________________
(In Billion Cubic Feet)

DISTRIBUTION OPERATIONS
Sales. . . . . . . . . . . . . 297.8 293.6 273.3
Transportation. . . . . . . . . . 145.4 143.5 134.4
_____ _____ _____
Throughput . . . . . . . . . . 443.2 437.1 407.7
===== ===== =====
TRANSMISSION OPERATIONS
Sales. . . . . . . . . . . . . 100.1 42.4 142.3
Transportation. . . . . . . . . . 610.9 596.8 403.7
_____ _____ _____
Throughput* . . . . . . . . . . 711.0 639.2 546.0
===== ===== =====

* Includes intercompany activity.
_______________________________________________________________________________

31

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

DISTRIBUTION

Sales growth in Consolidated'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., due
to customer conversions from other energy sources and the past and potential
future expansion of its service territory. Since Consolidated'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 Consolidated's other
distribution subsidiaries. In 1993, Virginia Natural Gas connected about 7,800
new residential and commercial customers. The completion in 1992 of the 135-
mile intrastate pipeline in Virginia has provided Virginia Natural Gas and its
customers with new gas supply sources through access to Consolidated's
transmission system and storage facilities and has afforded additional
opportunities for growth in both gas sales and transportation, especially in
the power generation markets. Additional growth in distribution operations may
also occur as industrial customers and electric generators turn to natural gas
as a means to ensure compliance with the provisions of the Clean Air Act. In
this connection, the development of new gas-burning technologies for industry
and the wider acceptance of natural gas as a fuel for motor vehicles provide
opportunities for increased gas usage in market sectors that are not weather-
sensitive.

Gas sales of the distribution subsidiaries were somewhat higher in 1993 due to
slightly colder weather while transportation volumes remained relatively
unchanged from 1992. The net addition of approximately 17,800 customers in
1993 also contributed to the higher sales volumes. The weather in 1993 was 2
percent colder than in 1992, resulting in higher space-heating sales.
Residential gas sales increased 4.2 Bcf to 212.3 Bcf in 1993, and commercial
sales volumes were virtually unchanged at 72.7 Bcf. Industrial sales volumes
were flat with 1992 at 12.5 Bcf, while transportation volumes for industrial
customers were up 1.5 Bcf to 116.0 Bcf. Gas transported for commercial
customers was 21.1 Bcf in 1993, up 1.4 Bcf compared with 1992, while
transportation to off-system customers declined by 1.0 Bcf to 8.3 Bcf in 1993.

Significantly colder weather and increased economic activity were the primary
reasons for the increased gas deliveries by the distribution operations in 1992
compared with 1991. The weather, which overall was 12 percent colder than in
1991, resulted in increased gas usage by space-heating customers. Residential
gas sales volumes increased 15.8 Bcf in 1992 to 208.1 Bcf, while sales to
commercial customers were up 3.2 Bcf to 72.6 Bcf. Sales to industrial
customers were 12.5 Bcf, up 1.3 Bcf over 1991, and transportation volumes for
these customers increased 4.8 Bcf to 114.5 Bcf. Transportation for commercial
customers was also higher in 1992, increasing by 2.5 Bcf.

TRANSMISSION

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 the Company's transmission operations
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. The changing regulatory environment has also 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
Consolidated'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.

32

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

CNG Transmission implemented Order 636 effective October 1, 1993 and, as
required by the Order, "unbundled" its services and revised its customer
contracts and service tariffs. 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. With the
implementation of Order 636, 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. However,
Consolidated continues to provide the equivalent of "bundled" services through
its unregulated CNG Gas Services subsidiary.

Consolidated's transmission operations achieved a record level of throughput in
1993. Total transmission throughput volumes were 711.0 billion cubic feet
(Bcf), an increase of 71.8 Bcf compared with 639.2 Bcf in 1992. Wholesale gas
sales volumes increased 57.7 Bcf in 1993 to 100.1 Bcf. The increase in sales
volumes was due to the sale by CNG Transmission of approximately 58 Bcf of gas
from storage inventory in anticipation of the transition to restructured
services. These sales, which were made primarily to customers outside the
traditional Northern Market area at reduced prices under alternative FERC-
approved tariff schedules, increased available capacity to provide future
storage service and reduced certain transition costs under Order 636. Total
gas transportation volumes in 1993 increased 14.1 Bcf to 610.9 Bcf. The
increase in transportation volumes occurred in the fourth quarter of 1993
following CNG Transmission's implementation of Order 636 and was due primarily
to volumes transported for customers in the Northern Market area and Virginia.

Total transmission throughput volumes in 1992 were 639.2 Bcf, an increase of
93.2 Bcf compared with 1991. Market expansion, increased demand in the
Northern Market area, and higher deliveries to power generation customers, were
the major factors affecting gas sales and transportation volumes in 1992.
Wholesale gas sales volumes declined 99.9 Bcf to 42.4 Bcf as utility customers
switched from sales to transportation service under the restructured service
agreements which resulted from the settlement of CNG Transmission's previous
rate filings. The decline in sales volumes also reflects the sale-in-place
during 1991 of 13.7 Bcf of gas inventories. Total gas transportation volumes
were up 193.1 Bcf over 1991 to 596.8 Bcf. The expansion of service to new and
existing customers, colder weather, and renewed demand in the Northern Market
were the major factors for the increase.

GAS AND OIL PRODUCTION AND PRICES

The following table sets forth Consolidated's gas and oil production and
average wellhead prices for the exploration and production operations for the
last three years:
_______________________________________________________________________________
PRODUCTION 1993 1992 1991
_______________________________________________________________________________
GAS (BCF)
Nonregulated. . . . . . . . . . 123.5 121.3 125.7
Regulated (Cost-of-service). . . . . 6.0 6.7 7.1
_______ _______ _______
Total. . . . . . . . . . . 129.5 128.0 132.8
======= ======= =======

OIL (000 BBLS)
Nonregulated. . . . . . . . . . 3,906.8 4,507.7 5,245.6
Regulated (Cost-of-service). . . . . 29.1 31.3 33.3
_______ _______ _______
Total. . . . . . . . . . . 3,935.9 4,539.0 5,278.9
======= ======= =======

AVERAGE WELLHEAD PRICES
(NONREGULATED ONLY)
Gas (per Mcf) . . . . . . . . . $ 2.24 $ 2.05 $ 1.96
Oil (per Bbl) . . . . . . . . . $ 15.66 $ 18.15 $ 19.53
_______________________________________________________________________________

33

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

Although gas production increased slightly in 1993 compared with 1992, reduced
deliverability at certain properties and the sale of selected properties in the
Appalachian area held production below the level achieved in 1991. The reduced
deliverability was due in part to the postponement in past years of workover
activity due to the weak prices in gas markets. Gas wellhead prices remained
strong in 1993 and were above 1992 levels for most of the year. For the year,
Consolidated's average gas wellhead price was up $.19 a thousand cubic feet
over 1992. The lower oil production in 1993 was attributable primarily to
normal production declines at older properties. Following world oil price
trends, Consolidated's average oil price declined in 1993 as prices remained
weak through most of the year and fell sharply near year-end.

Gas production in 1992 was down 4 percent and oil production declined 14
percent from 1991. The lower production was due to a combination of factors,
including the selective shut-in of wells, particularly early in 1992 when
prices were low, the interruption of operations caused by Hurricane Andrew, and
reduced deliverability at certain properties. Gas spot market prices for the
industry dropped to a low of about $1.00 a thousand cubic feet in February
1992, but strengthened considerably in the second and third quarters of the
year due to cold spring weather and concerns over supply shortages following
the hurricane. Consolidated's gas wellhead prices in 1992 were up $.09 a
thousand cubic feet, while average oil prices declined in 1992, as prices
remained lower throughout most of the year reflecting the trend in world oil
prices.

OPERATING REVENUES

Operating revenues, which include revenues from gas and oil sales,
transportation of gas, storage service, brokering activities and by-product
operations, are shown below by business component:

______________________________________________________________________________
OPERATING REVENUES 1993 1992 1991
______________________________________________________________________________
(In Millions)
Distribution. . . . . . . . . $1,773.9 $1,603.1 $1,531.0
Transmission. . . . . . . . . 983.8 642.7 878.9
Exploration and production . . . . 536.4 519.4 502.6
Other . . . . . . . . . . . 357.8* 85.7 77.8
Intercompany eliminations
and adjustments . . . . . . . (467.8) (330.0) (383.3)
________ ________ ________
Total. . . . . . . . . . $3,184.1 $2,520.9 $2,607.0
======== ======== ========

* Includes $325.7 million of revenues of CNG Gas Services.
______________________________________________________________________________

Total operating revenues were up $663.2 million in 1993 with the increase due
to higher gas sales revenues. Total gas sales revenues increased $663.5
million due to higher retail sales volumes and rates, the sale of gas from
storage inventory, higher gas wellhead prices and production, and the initial
year of marketing activities by CNG Gas Services. Other operating revenues
declined slightly from 1992. Increased gas transportation and storage service
revenues and higher revenues from by-product sales were offset by the impact of
lower oil and condensate revenues.

Lower gas sales revenues were the primary reason for the decline in total
operating revenues in 1992 compared with 1991. Total gas sales revenues in
1992 were down $131.4 million due primarily to the shift by wholesale customers
from sales to transportation service. Revenues from oil production and
brokering and from by-product sales were also lower in 1992. Increases in
retail sales volumes, gas transportation revenues, gas wellhead prices, gas
brokering activity, and storage service revenues only partially offset the
impact of these revenue declines.

34

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

The total average unit selling price of gas in 1993 was $4.33 per thousand
cubic feet, down slightly from $4.35 in 1992. In 1991, the average unit
selling price was $4.29 per thousand cubic feet. Average sales prices in 1993
were higher for all retail categories and for sales of the Company's gas
production. However, CNG Transmission's sales from storage inventory had a
significant influence on the overall average unit selling price since such
sales were made at lower rates under alternative FERC-approved tariff
schedules. The higher selling price in 1992 compared with 1991 reflects the
upward industry trend in gas wellhead prices experienced in 1992.

Operating revenues of the gas distribution operations in 1993 increased $170.8
million. Gas sales revenues rose $171.6 million due to both higher sales
volumes and rates. Colder weather and an increase in the number of customers
served were the principal reasons for the sales volume increase. The full year
impact of general rate increases placed into effect in late 1992 by Peoples
Natural Gas and Virginia Natural Gas, and an increase which became effective in
1993 for Hope Gas, Inc., contributed approximately $21.8 million to sales
revenues in 1993. The recovery in current rates of previously incurred gas
cost increases also contributed to the higher revenues in 1993. Other
operating revenues declined $.8 million due primarily to lower storage service
revenues.

Revenues of the gas distribution operations rose $72.1 million in 1992 compared
with 1991. Gas sales revenues increased $59.0 million as colder weather
resulted in higher residential and commercial sales volumes. The general rate
increase granted to Hope Gas in 1991 and rate increases placed into effect by
Peoples Natural Gas and Virginia Natural Gas in the latter part of 1992
contributed about $8.2 million to sales revenues in 1992. Other operating
revenues were up $13.1 million in 1992, primarily as the result of increased
transportation revenues due to higher deliveries to industrial and commercial
customers and facilities use charges associated with the Virginia intrastate
pipeline.

Operating revenues of the gas transmission operations over the past three years
have fluctuated as CNG Transmission moved toward the implementation of FERC
Order 636. In 1993, operating revenues were up $341.1 million, a significant
portion of which is attributable to higher gas sales revenues. Wholesale gas
sales revenues rose $290.0 million due chiefly to billings by CNG Transmission
of its October 1, 1993, balance of certain Order 636 transition costs and the
sales of approximately 58 Bcf of gas from storage inventory in anticipation of
the implementation of Order 636. Gas transportation revenues were up $35.7
million and storage service revenues increased $12.6 million, both reflecting
the increased level of services provided customers under Order 636. Revenues
from the sale of by-products were also higher in 1993, increasing $4.5 million
primarily as the result of higher propane and ethane sales volumes.

Operating revenues of the gas transmission operations in 1992 and 1991 reflect
the impact of the restructured service agreements which resulted from CNG
Transmission's 1988 rate case settlement. Wholesale sales revenues were
reduced in both years and transportation revenues were higher in 1992 as
customers switched from sales to transportation service. The effect on sales
revenues, however, does not parallel the change in transportation revenues due
to the commodity cost associated with the gas sales volumes. In 1992,
operating revenues of the transmission operations were down $236.2 million
compared with 1991. Sales revenues declined $304.0 million and transportation
revenues rose $54.4 million primarily as a result of the volumetric changes.
The comparison of transportation revenues is also affected by a $10.3 million
refund reclassification charge related to prior years, which was recorded in
1991 as part of a rate settlement. Storage service revenues in 1992 increased
$11.7 million due to the increased access by customers to the Company's storage
facilities.

35

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

Operating revenues from exploration and production operations increased $17.0
million in 1993. Gas sales revenues rose $43.5 million due to higher prices
received, an increase in the volume of gas brokering activity and slightly
higher gas production. However, a large portion of this gain was offset by
lower oil and condensate revenues. Oil and condensate revenues declined $35.5
million as lower prices and volumes adversely affected revenues from both oil
production and brokering activities. Revenues from the sale of oil and
condensate production declined $20.8 million, while revenues from oil brokering
were down $14.7 million. Other revenues of the exploration and production
operations were up $9.0 million in 1993 as the result of increased royalties
received due to the higher gas prices and business interruption insurance
reimbursements related to Hurricane Andrew.

Exploration and production revenues in 1992 were up $16.8 million compared with
1991. Gas revenues increased $46.9 million due to increased gas brokering
activity and higher prices received for both the sale of Company production and
volumes brokered. The impact of lower gas production only partially offset
these gains. Oil and condensate revenues fell $34.8 million in 1992. Revenues
from the sale of oil and condensate production were down $20.0 million due to
lower production and wellhead prices, while revenues from the Company's
brokered oil program declined $14.8 million due to lower volumes and prices.
Hurricane Andrew did not have a significant effect on 1992 operating revenues
due to business interruption insurance coverage.

OPERATING EXPENSES

Operating expenses, including taxes, increased 30 percent in 1993 to $2.93
billion. Operating expenses in 1992 were $2.25 billion, down 5 percent from
$2.38 billion in 1991.

Purchased gas costs consistently represent the largest expense item for
Consolidated. Purchased gas costs were $1,603.0 million in 1993, $990.6
million in 1992 and $1,157.1 million in 1991. These costs are 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.
Increased volume requirements, CNG Transmission's billing of its October 1,
1993, balance of unrecovered gas and transportation costs under Order 636 and
higher spot market gas prices were the principal reasons for the increased
costs in 1993. The sales of approximately 58 Bcf of gas from storage inventory
by CNG Transmission and increased recoveries of previously deferred gas costs
by the distribution subsidiaries also contributed to the higher level of
expense in 1993. Lower volume requirements and the resulting lower recoveries
of gas costs previously deferred were the major factors for the decline in
overall purchased gas costs in 1992.

"Other purchased products" includes the cost of liquids and by-products
purchased for resale and, beginning in 1992, the cost of pipeline capacity not
associated with gas purchased. The decrease in these costs in 1993 and 1992
generally reflects the lower volumes of oil purchased and resold in connection
with the Company's brokered oil program.

Consolidated's combined operation expense and maintenance increased $23.5
million, or 4 percent, in 1993 to $685.7 million. Operation expense was up
$15.4 million to $598.5 million principally due to increased payroll and
benefit expenses and gas and oil production-related costs. Maintenance expense
in 1993 was up $8.1 million to $87.2 million largely because of additional work
performed with respect to distribution and transmission mains, compressor
station maintenance and environmental-related costs. The adoption in 1993 of
SFAS No. 106, which requires the accrual of postretirement health care and life
insurance costs, did not have a significant impact on operation expense since
the vast majority of the increased costs under SFAS No. 106 has been deferred
pending recovery in future rates. Reference is made to Note 6 to the
consolidated financial statements for additional information regarding this new
accounting standard. In 1992, combined operation expense and maintenance

36

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

increased 4 percent to $662.2 million. Operation expense increased $16.4
million to $583.1 million primarily as the result of higher payroll and
overhead costs and increased environmental-related costs. These higher costs
were partially offset by a decline in production-related expenses due to lower
gas and oil production volumes and cost containment efforts. Maintenance
increased $6.3 million to $79.1 million in 1992 due chiefly to additional work
performed to ensure service reliability of distribution mains.

The following table presents the depreciation and amortization expense for
Consolidated's business components for the last three years:
_______________________________________________________________________________
DEPRECIATION AND AMORTIZATION 1993 1992 1991
_______________________________________________________________________________
(In Millions)
Distribution. . . . . . . . . . . $ 65.3 $ 61.0 $ 56.9
Transmission. . . . . . . . . . . 50.4 43.8 39.2
Exploration and production . . . . . . 176.7 180.8 186.3
Other . . . . . . . . . . . . . 2.2 2.2 2.3
______ ______ ______
Total. . . . . . . . . . . . $294.6 $287.8 $284.7
====== ====== ======
_______________________________________________________________________________

Depreciation expense for the distribution operations increased in both 1993 and
1992 due to the higher level of plant investment. These higher amounts
reflect, for the most part, depreciation charges for the Virginia intrastate
pipeline which was placed in service during 1992. The increased expense in
1993 and 1992 for transmission operations reflects the higher plant investment
resulting from the completion of substantially all of its major pipeline
expansion projects. Amortization charges of the exploration and production
operations decreased in 1993 and 1992 due primarily to lower oil production.

Taxes, other than income taxes, increased by $11.7 million in 1993 compared
with an $8.7 million increase in 1992. These increases were due in large part
to higher property taxes.

Income taxes for 1993 reflect the implementation of SFAS No. 109, while taxes
for 1992 and 1991 were determined under the previous accounting standard.
Reference is made to Note 7 to the consolidated financial statements for
information regarding the adoption of SFAS No. 109, as well as for information
on the effects of the increase in 1993 in the federal corporate income tax
rate. "Income taxes - estimated" increased $31.3 million in 1993. Additional
deferred income taxes recorded in 1993 as a result of the tax rate increase and
higher pretax earnings were the primary reasons for the increased tax expense.
Certain deferred tax benefits which reduced income tax expense in 1992 under
the previous accounting standard were also a significant factor in the
comparison. Income taxes in 1992 increased compared with 1991 due to higher
pretax earnings and increased state income taxes.

NEW ACCOUNTING STANDARD

In November 1992, the FASB issued Statement of Financial Accounting Standards
No. 112, "Employers' Accounting for Postemployment Benefits." This Statement
establishes the accounting for certain benefits provided to inactive and former
employees prior to retirement. Consolidated will adopt the provisions of this
standard in the first quarter of 1994 as required. Based on management's
current estimates and assumptions, the adoption of the standard is not expected
to have a material effect on Consolidated's financial position, results of
operations or cash flows.

37

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). Under this method, the total capitalized costs, net of
related deferred taxes, are subject to a limitation based on the present value
of estimated future net revenues expected to be received from the production of
proved reserves. If net capitalized costs exceed this amount at the end of any
quarter, a permanent impairment of the assets is required to be charged to
expense in that period.

Consolidated has never been required to recognize such an impairment under the
SEC full cost rules. There are a number of factors, including prices, that
determine whether or not an impairment is required. Gas wellhead prices
remained strong during 1993, and have continued to be firm in the early part of
1994 due in part to higher demand caused by the colder weather. 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.

OTHER INCOME AND INTEREST CHARGES

Total other income was $10.5 million in 1993, $4.7 million in 1992 and $26.3
million in 1991. Interest revenues were up $1.5 million in 1993 due primarily
to the recognition of interest in connection with certain regulatory programs.
Interest revenues in 1992 reflect lower revenues in connection with take-or-pay
recoveries by the subsidiaries and the lower interest rates which prevailed
during that year. Interest revenues were unusually high in 1991 due primarily
to the recognition of $13.9 million of interest income in connection with
refunds resulting from the settlement of certain tax matters related to prior
years. The changes in "Other (net)" in the Statement of Income for 1993 and
1992 reflect the differing levels of income recognized from the Company's
external investments. Income realized from the disposition of certain
nonregulated assets also contributed to the higher amount in 1991.

Interest on long-term debt was lower in 1993 and 1992 due to redemptions and
repayments of debenture borrowings. During 1993, the Company called $266.2
million of its higher-cost borrowings, while issuing $300 million of lower rate
debentures. Other interest expense declined in both 1993 and 1992 due
primarily to lower commercial paper discount rates in both years. Reduced
interest charges related to refund obligations to customers also contributed to
the decrease in 1992. The amount of interest expense capitalized has declined
in the past two years reflecting the completion of pipeline expansion projects
and reduced interest costs incurred.

38

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

FOURTH QUARTER RESULTS

Consolidated's net income for the fourth quarter of 1993 was $86.1 million
compared with $97.1 million earned in the 1992 fourth quarter, a decrease of
$11 million. On a per share basis, the 1993 quarter was $.93 compared with
$1.05 in 1992. However, the comparison is somewhat distorted due to the
inclusion in the 1992 fourth quarter of the favorable impacts of certain
deferred tax benefits under the then-applicable income tax accounting standard
and the reversal of a reserve related to the Company's abandoned liquefied
natural gas facilities. Excluding these items, fourth quarter net income would
show an improvement due primarily to increased gas deliveries by the Company's
transmission operations and colder weather. The weather in Consolidated's
retail service areas was 3 percent colder than in the 1992 fourth quarter.
These positive factors offset lower gas and oil wellhead prices experienced in
the quarter by the exploration and production operations. Gas wellhead prices
were down $.19 per thousand cubic feet compared with 1992 while oil wellhead
prices fell $4.01 per barrel.
______________________________________________________________________________
QUARTERS ENDED DECEMBER 31, 1993 1992
______________________________________________________________________________
(In Millions)
Operating revenues . . . . . . . . . . $1,030.2 $ 790.4
Operating expenses . . . . . . . . . . (930.4) (672.8)
________ _______
Operating income . . . . . . . . . . . 99.8 117.6
Other income/expenses (net) . . . . . . . (13.7) (20.5)
________ _______
Net income . . . . . . . . . . . . . $ 86.1 $ 97.1
======== =======
Per common share (in dollars). . . . . . . $.93 $1.05
Average shares outstanding (thousands). . . . 92,923 92,473
______________________________________________________________________________

FEDERAL AND STATE REGULATORY MATTERS

FERC ORDER 636

In April 1992, the FERC issued Order 636, a comprehensive set of regulations
designed to encourage competition and continue the significant restructuring of
the interstate natural gas pipeline industry that the FERC first set in motion
during 1985 with its Order 436. Under Order 636, interstate pipelines were
required to "unbundle" their services into separate sales, transportation and
storage services and to offer and price such services separately. Order 636
also changed the way in which rates are designed by requiring return on equity
and income taxes to be recovered as part of a fixed monthly charge. Under
previous rate design, these costs were recovered through usage or commodity
rates.

Order 636 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 cost 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.

39

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

On November 23, 1993, the FERC issued an Order allowing CNG Transmission to
begin collecting its unrecovered purchased gas and sales-related transportation
costs which were remaining at the October 1, 1993, implementation date. In
December 1993, CNG Transmission billed its customers (through a direct bill
mechanism) for these costs. The total principal amount to be collected based
on this Order was approximately $177.9 million. In accordance with the FERC
Order, CNG Transmission can seek recovery through March 1995 of additional
Order 636 transition costs incurred that relate to transactions prior to
October 1, 1993.

In accordance with the Settlement, CNG Transmission will absorb up to $3.5
million of GSR costs. GSR costs, however, were minimized since certain of the
Company's 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
distribution subsidiaries should generally be able to pass through to their
customers the costs associated with the assigned contracts in recognition of
the other benefits received in the Settlement.

The full extent of stranded costs for CNG Transmission are unknown at this
time. However, CNG Transmission has filed for recovery of $9.2 million of
stranded facilities costs in its December 30, 1993, general rate filing. CNG
Transmission will incur new facilities costs, including costs for new computer
hardware and software. Although a final overall estimate of new facilities
costs has not yet been determined, such costs may approach $50 million.
Consistent with FERC procedures, 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.

Although Order 636 applies directly to pipeline companies, it has also affected
the way in which gas distribution companies purchase gas supplies and contract
for transportation and storage services. The Company's distribution
subsidiaries have taken actions designed to adapt to the new environment
created by Order 636 and should generally be able to recover transition costs
passed through to them by the pipelines. Reference is made to Note 3 to the
consolidated financial statements for additional information regarding the
effects of Order 636 on the distribution subsidiaries, including the estimated
amount of future transition costs.

Other portions of the Company's operations have also been affected by Order
636. CNG Producing and CNG Gas Services have taken action to expand the
Company's customer base in response to the unbundling of sales service
previously offered by pipelines. New marketing strategies and contracts are
being developed to address customer needs for intermediate and long-term gas
supplies as well as other services which will be required in this "post-Order
636" era.

As a fully integrated gas system with production, transmission, distribution
and marketing subsidiaries, the Company believes it is in a position to compete
in new markets and to offer a broad range of unbundled gas services. 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.

40

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

CNG TRANSMISSION

On December 30, 1993, CNG Transmission filed a general rate filing with the
FERC requesting an annual revenue increase of $106.6 million. The rate
increase request is intended to cover higher operating costs, increased plant
investment, and the recovery of $9.2 million in transition costs related to
stranded facilities because of FERC Order 636. The increase is expected to
become effective, after the suspension period, on July 1, 1994, subject to
refund.

STATE REGULATORY ISSUES

On June 22, 1993, the Virginia State Corporation Commission approved a $10.4
million annual increase for Virginia Natural Gas. The new rates were effective
retroactive to September 4, 1992. In its April 1992 filing, Virginia Natural
Gas had requested a $14.1 million annual increase in revenues.

On October 28, 1993, Peoples Natural Gas filed with the Pennsylvania Public
Utility Commission for a $28.4 million increase in base rates. The rate
increase request is intended to cover higher operating expenses. If approved,
the new rates would become effective on August 6, 1994. Peoples Natural Gas
also filed to recover, over four years, $20.1 million in estimated transition
costs related to FERC Order 636.

On October 29, 1993, the Public Service Commission of West Virginia granted
Hope Gas an indicated $1.9 million annual revenue increase effective November
1, 1993. In its March 1993 filing, Hope Gas had requested an $8.2 million
increase in revenues. On November 8, 1993, Hope Gas filed a petition for
rehearing in the case.

On January 18, 1994, East Ohio Gas filed with the Public Utilities Commission
of Ohio for a $99.1 million increase in base rates. The rate increase request
is intended to cover higher operating costs and increases in plant investment.
A decision by Ohio regulators is expected in October 1994. In addition, East
Ohio is negotiating with customers and the Commission staff as to the future
recovery of transition costs to be incurred under Order 636.

41

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

ENVIRONMENTAL MATTERS

The Company and its subsidiaries are 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 Company and
its subsidiaries, or their predecessors.

As part of their normal business operations, the subsidiaries periodically
monitor their properties and facilities and resolve potential environmental
matters so as to remain in compliance with the various environmental laws and
regulations. The Company also conducts general environmental surveys on a
continuing basis at its operating facilities to assure compliance with these
laws and regulations. In this regard, voluntary surveys at subsidiary meter
sites were conducted to determine the extent of any possible soil contamination
due to mercury spillage. These studies, which are continuing, are not in
response to any governmental or regulatory directive, order or settlement
agreement and have not disclosed any mercury contamination for which the
remediation costs would be considered material to Consolidated's financial
position, results of operations or cash flows. 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. It is unknown at this
time whether civil penalties will be assessed. Pursuant to the Order and
Agreement, CNG Transmission is performing certain sampling, testing and
analysis, and conducting a program of remediation at some of its Pennsylvania
facilities. Total remediation costs in connection with the Order and Agreement
are not expected to be material with respect to Consolidated's financial
position, results of operations or cash flows. Based on current knowledge, the
Company has recognized a gross estimated liability amounting to $19,661,000 at
December 31, 1993, for future costs expected to be incurred to remediate or
mitigate hazardous substances at mercury sites and at facilities covered by the
Order and Agreement. The estimate for this liability was based on current
environmental laws and regulations and existing technology.

Inasmuch as certain environmental-related expenditures are expected to be
recoverable in future regulatory proceedings, a regulatory asset amounting to
$11,378,000 at December 31, 1993, is included in the Consolidated Balance Sheet
under the caption "Deferred charges and other noncurrent assets." Also,
uncontested claims amounting to $3,566,000 at December 31, 1993, were
recognized for environmental-related costs probable of recovery through joint-
interest operating agreements.

The total charges to operating expenses for environmental-related costs were
$3,205,000, $7,646,000, and $9,049,000, respectively, for the years ended
December 31, 1991 through 1993. Reference is made to Note 15 to the
consolidated financial statements for the components of these expenses. The
Company's environmental-related capital expenditures for monitoring or
complying with laws and regulations for 1991 through 1993 were not material.

The Company has determined that it is associated with 16 former manufactured
gas plant sites, five of which are currently owned by the Company. 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.

42

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

The exact nature of environmental issues that 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.

CNG Transmission and certain of the Company's distribution subsidiaries are
subject to the Federal Clean Air Act and the Federal Clean Air Act Amendments
of 1990 (1990 amendments) which added significantly to the existing
requirements established by the Federal Clean Air Act. These subsidiaries
operate compressor stations that are covered by the new nitrogen oxide emission
standard established as a result of the 1990 amendments. The Company will have
until May 31, 1995, to comply with the emission standard. The Company expects
that compliance will require significant capital expenditures to modify the
compressor engines along the Company's pipeline system. However, the actual
cost of compliance will be dependent upon the requirements imposed by the
environmental agencies of the states in which the compressor stations are
located. Based on the Company's preliminary estimates and analyses,
approximately $46 million of capital expenditures may be required. Actual
capital expenditures required to comply with the 1990 amendments are expected
to be recoverable through future regulatory proceedings.

EFFECTS OF INFLATION

Although inflation rates have been moderate, any change in price levels has an
effect on operating results due to the capital intensive and regulated nature
of Consolidated's major business components. Consolidated attempts to minimize
the effects of inflation through cost control, productivity improvements and
regulatory actions where appropriate.

For the Company's rate-regulated subsidiaries, increases in operating costs are
not generally subject to immediate recovery due to the time lag inherent in the
rate-making process. Also, only the historical cost of property, plant and
equipment is recoverable in revenues through depreciation. While the rate-
making process gives no recognition to the current cost of replacing
properties, Consolidated believes, based on past regulatory practices, that it
will be allowed to earn a return on the increased cost of its property
investment as replacement occurs.

For the exploration and production operations, gas and oil prices are based on
market supply and demand rather than the level of costs. Therefore,
Consolidated's exploration and production operations focus on balancing
production and sales levels with operating costs to minimize the effects of
inflation.

43

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

FINANCIAL CONDITION

DIVIDEND INCREASE AND COMMON STOCK MATTERS

In December 1993, the Board of Directors raised the annual dividend on the
common stock to $1.94 a share from $1.92 a share. The new quarterly rate is
48.5 cents a share, compared with 48 cents a share. This marked the 29th
consecutive year in which the dividend has been increased. Total dividends
paid to common shareholders in 1993 were $178.1 million compared with $168.5
million in 1992 and $163.1 million in 1991.

During 1993, a total of 376,811 original issue shares were acquired by
stockholders and employees through various Company-sponsored plans.
Stockholders participating in the Company's Dividend Reinvestment Plan
purchased a total of 57,750 shares, representing the reinvestment of $2,856,000
of dividends. A total of 303,561 shares were issued to employees under stock-
based incentive plans, including 237,957 shares acquired through the exercise
of outstanding stock options. In addition, 15,500 new issue shares were
purchased by employees through the System's Thrift Plans. During 1993, certain
share requirements of the Thrift Plans, as well as the shares required for the
Company's Employee Stock Ownership Plan, were satisfied through open market
purchases.

Under the Company's stock repurchase plan, up to 4 million shares of the
outstanding common stock can be repurchased through December 31, 1995. The
shares may be purchased in the open market from time-to-time, depending on
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, 1992. During 1993, no open market purchases
were made by the Company. The Company acquired 29,212 shares in 1993 through
the provisions of its incentive plans at a cost of $1.4 million, or an average
price of $48.51 a share. All of these shares were sold before year-end to the
System's Thrift Plans.

CAPITAL SPENDING

As shown in the table below, capital expenditures were $342.6 million in 1993,
compared with $441.5 million in 1992.
_______________________________________________________________________________
CAPITAL EXPENDITURES 1994* 1993 1992
_______________________________________________________________________________
(In Millions)
Distribution. . . . . . . . . . . $141.8 $115.4 $114.7
Transmission. . . . . . . . . . . 124.4 113.4 225.3
Exploration and production . . . . . . 153.0 110.7 99.1
Other . . . . . . . . . . . . . 20.4 3.1 2.4
______ ______ ______
Total. . . . . . . . . . . . $439.6 $342.6 $441.5
====== ====== ======
* Estimated.
_______________________________________________________________________________

44

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

The current capital budget for 1994 is estimated at $439.6 million, a 28
percent increase compared with spending in 1993. The higher level of capital
expenditures anticipated for 1994 reflects increased spending for exploration
and production operations, including funds for work on the "Popeye" deep-water
development project in the Gulf of Mexico. Expenditures for the distribution
and transmission operations will primarily be for enhancements and improvements
in the pipeline network and related facilities, and expected capital
expenditures to comply with the 1990 Federal Clean Air Act Amendments. The
increase in the "Other" category reflects a higher level of expenditures in
connection with the Lakewood cogeneration project.

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. Additional funds, if necessary, could be obtained through
borrowings under the Company's credit agreement or through the issuance of new
debt securities.

The following table presents the total gross investment in property, plant and
equipment of each of Consolidated's business components at December 31, 1993
and 1992:
_______________________________________________________________________________
TOTAL GROSS INVESTMENT IN PROPERTY,
PLANT AND EQUIPMENT 1993 1992
_______________________________________________________________________________
(In Millions)
Distribution. . . . . . . . . . . . . $2,380.1 $2,281.7
Transmission. . . . . . . . . . . . . 1,916.8 1,812.1
Exploration and production . . . . . . . . 2,983.0 2,929.7
Other . . . . . . . . . . . . . . . 66.1 63.6
________ ________
Total. . . . . . . . . . . . . . $7,346.0 $7,087.1
======== ========
_______________________________________________________________________________

Although the Company plans to increase spending in 1994 for its exploration and
production operations, it will continue to monitor its investment in these
operations in light of changing market conditions. The sale of the Company's
remaining interests in gas and oil producing properties in Canada is possible
depending on economic conditions. Proved reserves associated with Canadian
properties approximated 1.1 Bcf of gas and 5.7 million barrels of oil at
December 31, 1993. On an energy-equivalent basis, these reserves represent
about 3 percent of Consolidated's total proved reserves at that date.

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 obtained in the first
half of the year. However, cash requirements for capital expenditures,
dividends, long-term debt retirement and working capital 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 Statement of Cash Flows, net cash provided by
operating activities was $470.9 million, $405.4 million and $497.9 million for
the years 1993, 1992 and 1991, respectively. Higher gas sales and
transportation revenues in 1993 and refunds made to customers in 1992 amounting
to $63 million in connection with the final settlement of a CNG Transmission
rate case were the primary factors for the increase in net operating cash flows
in 1993 compared with 1992. Federal income tax refunds received in 1991
contributed to that year's operating cash flows.

45

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

During 1993, the Company retired $279,650,000 principal amount of its
debentures, of which $266,150,000 represents debentures called at the option of
the Company. The Company used short-term borrowings and internally-generated
funds to redeem an aggregate of $118,150,000 of debentures in May and June of
1993. On August 16, 1993, an additional $148,000,000 of debentures were
redeemed. On August 24, 1993, the Company sold $150 million of 5 3/4%
debentures, using the net proceeds from the sale, along with available funds,
to repay short-term debt incurred in connection with the August 16 redemption.
Also, in December 1993, the Company sold $150 million of 6 5/8% debentures.
The net proceeds from this sale were used to repay short-term borrowings in
connection with the May and June redemptions and to finance capital
expenditures.

The Company has a currently effective shelf registration with the SEC that
permits the sale of up to $100 million of debentures. The Company plans to
file a new shelf registration in 1994 that would permit the sale of an
additional $400 million of debentures.

At December 31, 1993, the Company had a $300 million credit agreement with a
group of banks. At various times during 1993, the Company utilized borrowings
under this agreement primarily to provide temporary financing for capital
expenditures. The maximum amount outstanding at any one time during 1993 was
$125 million. There were no amounts outstanding under this credit agreement at
December 31, 1993 and 1992.

The Company's embedded long-term debt cost, excluding current maturities, at
year-end 1993 was 7.75 percent, compared with 8.18 percent for 1992 and 8.38
percent for 1991. The long-term debt to capitalization ratio was 34.7 percent
at the end of 1993, and 34.3 percent and 38.0 percent at year-end 1992 and
1991, 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.

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 1993, of which $455 million was outstanding at
year-end. Bank lines of credit amounting to $475 million are available to
provide backup if the sale of commercial paper notes is not feasible. In
addition to these credit lines, the Company may utilize unused portions of its
credit agreement to provide support for commercial paper notes.

SUMMARY OF FINANCIAL DATA

The Company's Summary of Financial Data is on page 26.

46

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 17(A), page 72; Quarterly Financial Data -- Note 17(B), page 76.

FINANCIAL STATEMENTS

INDEX
_______________________________________________________________________________
Page
_______________________________________________________________________________

Report of Independent Accountants. . . . . . . . . . . . 48
Consolidated Statement of Income for the Years 1991 through 1993 . 49
Consolidated Balance Sheet at December 31, 1992 and 1993 . . . . 50
Consolidated Statement of Cash Flows for the Years 1991 through 1993 52
Notes to Consolidated Financial Statements. . . . . . . . . 53

Schedule V - Property, Plant and Equipment. . . . . . . . . 78
Schedule VI - Accumulated Depreciation, Depletion and Amortization
of Property, Plant and Equipment. . . . . . . 82
Schedule VIII - Valuation and Qualifying Accounts . . . . . . Note 2
Schedule IX - Short-term Borrowings . . . . . . . . . . . 86
Schedule X - Supplementary Income Statement Information . . . . 87

Notes:
(1) Schedules I, II, III, IV, VII, XI, XII, XIII, and XIV have been
excluded because they are not applicable.
(2) Omitted inasmuch as amounts involved are not significant.
_______________________________________________________________________________

47

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 47 present fairly, in all material respects, the
financial position of Consolidated Natural Gas Company and subsidiaries at
December 31, 1993 and 1992, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1993, 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. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions," and Statement of
Financial Accounting Standards No. 109, "Accounting for Income Taxes," in 1993.

PRICE WATERHOUSE

Price Waterhouse

600 Grant Street
Pittsburgh, Pennsylvania 15219-9954
February 16, 1994

48

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
CONSOLIDATED STATEMENT OF INCOME

_______________________________________________________________________________
_______________________________________
For the Years Ended December 31,
1993 1992 1991
_______________________________________________________________________________
_______________________________________

(Thousands of Dollars)

OPERATING REVENUES
Regulated gas sales
Residential and commercial. . . . . . . . . . . . . . .
$1,595,142 $1,428,716 $1,373,062
Industrial . . . . . . . . . . . . . . . . . . . .
55,347 49,981 46,008
Wholesale . . . . . . . . . . . . . . . . . . . .
422,698 190,822 426,861
Nonregulated gas sales. . . . . . . . . . . . . . . . .
541,849 282,026 236,996

__________ __________ __________
Total gas sales. . . . . . . . . . . . . . . . . .
2,615,036 1,951,545 2,082,927
Other operating revenues . . . . . . . . . . . . . . . .
569,049 569,305 524,079

__________ __________ __________
Total operating revenues (Notes 2 and 3) . . . . . . . . .
3,184,085 2,520,850 2,607,006

__________ __________ __________

OPERATING EXPENSES
Purchased gas. . . . . . . . . . . . . . . . . . . .
1,603,048 990,604 1,157,096
Other purchased products . . . . . . . . . . . . . . . .
62,290 68,573 80,131
Operation expense (Schedule X, page 87) . . . . . . . . . . .
598,495 583,125 566,665
Maintenance (Schedule X, page 87) . . . . . . . . . . . . .
87,207 79,128 72,865
Depreciation and amortization (Note 4) . . . . . . . . . . .
294,648 287,840 284,712
Taxes, other than income taxes (Schedule X, page 87). . . . . . .
181,053 169,315 160,632

__________ __________ __________
Subtotal . . . . . . . . . . . . . . . . . . . .
2,826,741 2,178,585 2,322,101

__________ __________ __________
Operating income before income taxes. . . . . . . . . . .
357,344 342,265 284,905
Income taxes - estimated (Note 7) . . . . . . . . . . . . .
99,906 68,623 54,844

__________ __________ __________
Operating income . . . . . . . . . . . . . . . . .
257,438 273,642 230,061

__________ __________ __________

OTHER INCOME
Interest revenues . . . . . . . . . . . . . . . . . .
3,317 1,801 18,038
Gain on purchase of debentures for sinking funds . . . . . . . .
926 2,247 2,374
Other (net) . . . . . . . . . . . . . . . . . . . .
6,288 701 5,969

__________ __________ __________
Total other income. . . . . . . . . . . . . . . . .
10,531 4,749 26,381

__________ __________ __________
Income before interest charges. . . . . . . . . . . . .
267,969 278,391 256,442

__________ __________ __________

INTEREST CHARGES
Interest on long-term debt . . . . . . . . . . . . . . .
85,265 93,594 96,528
Other interest expense. . . . . . . . . . . . . . . . .
4,995 7,170 14,727
Total allowance for funds used during construction (credit) . . . .
(10,785) (17,331) (23,426)

__________ __________ __________
Total interest charges . . . . . . . . . . . . . . .
79,475 83,433 87,829

__________ __________ __________
Income before cumulative effect of change
in accounting principle. . . . . . . . . . . . . . . .
188,494 194,958 168,613
Cumulative effect prior to January 1, 1993,
of applying SFAS No. 109 (Note 7) . . . . . . . . . . . .
17,422 - -

__________ __________ __________

NET INCOME. . . . . . . . . . . . . . . . . . . . .
$ 205,916 $ 194,958 $ 168,613

========== ========== ==========

Earnings per share of common stock
Income before cumulative effect of change
in accounting principle. . . . . . . . . . . . . .
$2.03 $2.19 $1.94
Cumulative effect prior to January 1, 1993,
of applying SFAS No. 109 (Note 7) . . . . . . . . . .
.19 - -

_____ _____ _____
Net Income. . . . . . . . . . . . . . . . . . .
$2.22 $2.19 $1.94

===== ===== =====
Average common shares outstanding (thousands). . . . . . . .
92,808 89,128 86,837
_______________________________________________________________________________
_______________________________________
The Notes to Consolidated Financial Statements are an integral part of this
statement.

49

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
CONSOLIDATED BALANCE SHEET

_______________________________________________________________________________
__________________________
At December 31,
1993 1992
_______________________________________________________________________________
__________________________

(Thousands of Dollars)

ASSETS

PROPERTY, PLANT AND EQUIPMENT (Note 4)
Gas utility and other plant (Schedule V, page 78). . . . . . . $
4,362,996 $ 4,157,384
Accumulated depreciation and amortization (Schedule VI, page 82). .
(1,607,606) (1,515,258)

___________ ___________
Net gas utility and other plant. . . . . . . . . . .
2,755,390 2,642,126

___________ ___________
Exploration and production properties (Schedule V, page 78) . . .
2,983,032 2,929,718
Accumulated depreciation and amortization (Schedule VI, page 82). .
(1,822,154) (1,696,944)

___________ ___________
Net exploration and production properties . . . . . . .
1,160,878 1,232,774

___________ ___________
Net property, plant and equipment . . . . . . . . . .
3,916,268 3,874,900

___________ ___________

CURRENT ASSETS
Cash and temporary cash investments . . . . . . . . . . .
27,122 43,355
Accounts receivable
Customers . . . . . . . . . . . . . . . . . . .
461,108 388,985
Other. . . . . . . . . . . . . . . . . . . . .
176,005 145,503
Allowance for doubtful accounts . . . . . . . . . . . .
(7,640) (7,678)
Inventories, at cost
Gas stored - current portion (LIFO method) (Note 8) . . . . .
140,848 118,819
Construction and operating materials and
supplies (average cost method). . . . . . . . . . . .
38,784 38,601
Unrecovered gas costs (net) (Note 3) . . . . . . . . . . .
(9,000) 264,942
Deferred income taxes - current portion (Note 7) . . . . . . .
23,685 (86,149)*
Prepayments and other current assets . . . . . . . . . . .
192,212 204,904

___________ ___________
Total current assets . . . . . . . . . . . . . .
1,043,124 1,111,282

___________ ___________

OTHER ASSETS (Note 9)
Unamortized abandoned facilities . . . . . . . . . . . .
52,676 63,869
Other investments . . . . . . . . . . . . . . . . .
39,600 42,303
Deferred charges and other noncurrent assets
(Notes 3, 6, 7 and 15) . . . . . . . . . . . . . . .
357,918 63,308

___________ ___________
Total other assets . . . . . . . . . . . . . . .
450,194 169,480

___________ ___________

Total assets . . . . . . . . . . . . . . . . . $
5,409,586 $ 5,155,662

=========== ===========
_______________________________________________________________________________
__________________________
* Reclassified for comparative purposes.
The Notes to Consolidated Financial Statements are an integral part of this
statement.

50

ITEM 8.
(Cont.)

_______________________________________________________________________________
__________________________
At December 31,
1993 1992
_______________________________________________________________________________
__________________________

(Thousands of Dollars)

STOCKHOLDERS' EQUITY AND LIABILITIES

CAPITALIZATION
Common stockholders' equity (Note 10)
Common stock, par value $2.75 per share,
200,000,000 authorized shares
Issued, 1993 - 92,933,828 shares, 1992 - 92,557,017 shares . . $
255,568 $ 254,532
Capital in excess of par value . . . . . . . . . . . .
454,081 439,029
Retained earnings (Note 12) . . . . . . . . . . . . .
1,466,783 1,439,277

___________ ___________
Total common stockholders' equity . . . . . . . . . .
2,176,432 2,132,838
Long-term debt (Note 13) . . . . . . . . . . . . . . .
1,158,648 1,111,956

___________ ___________
Total capitalization . . . . . . . . . . . . . .
3,335,080 3,244,794

___________ ___________

CURRENT LIABILITIES
Current maturities on long-term debt . . . . . . . . . . .
- - 30,061
Commercial paper (Note 14) (Schedule IX, page 86). . . . . . .
455,000 460,000
Accounts payable. . . . . . . . . . . . . . . . . .
345,126 328,700
Estimated rate contingencies and refunds (Note 3). . . . . . .
57,456 79,386
Taxes accrued. . . . . . . . . . . . . . . . . . .
112,098 95,189
Dividends declared . . . . . . . . . . . . . . . . .
45,073 44,427
Other accruals and current liabilities . . . . . . . . . .
98,145 113,798

___________ ___________
Total current liabilities. . . . . . . . . . . . .
1,112,898 1,151,561

___________ ___________

DEFERRED CREDITS
Deferred income taxes (Note 7) . . . . . . . . . . . . .
783,511 669,407
Accumulated deferred investment tax credits. . . . . . . . .
35,849 38,469
Other deferred credits and noncurrent liabilities (Note 7). . . .
142,248 51,431

___________ ___________
Total deferred credits. . . . . . . . . . . . . .
961,608 759,307

___________ ___________

COMMITMENTS AND CONTINGENCIES (Note 16)
___________ ___________

Total stockholders' equity and liabilities . . . . . . . $
5,409,586 $ 5,155,662

=========== ===========
_______________________________________________________________________________
__________________________

51

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
CONSOLIDATED STATEMENT OF CASH FLOWS

_______________________________________________________________________________
_______________________________________
For the Years Ended December 31,
1993 1992 1991
_______________________________________________________________________________
_______________________________________

(Thousands of Dollars)

CASH FLOWS FROM OPERATING ACTIVITIES
Net income. . . . . . . . . . . . . . . . . . . .
$ 205,916 $ 194,958 $ 168,613
Adjustments to reconcile net income to net cash
provided by operating activities
Cumulative effect prior to January 1, 1993, of applying
SFAS No. 109 . . . . . . . . . . . . . . . . .
(17,422) - -
Depreciation and amortization . . . . . . . . . . . .
294,648 287,840 284,712
Deferred income taxes (net). . . . . . . . . . . . .
(19,782) 47,470 22,090
Investment tax credit. . . . . . . . . . . . . . .
(2,620) (2,691) (2,639)
Certain changes in current assets and current liabilities
Accounts receivable, less allowance for
doubtful accounts. . . . . . . . . . . . . . .
(107,292) 1,034 72,362
Inventories . . . . . . . . . . . . . . . . .
(22,212) 20,977 55,580
Unrecovered gas costs (net) . . . . . . . . . . . .
273,942 (122,769) (24,071)
Accounts payable. . . . . . . . . . . . . . . .
13,831 (31,168) (62,986)
Estimated rate contingencies and refunds. . . . . . . .
(21,930) (32,704) (16,378)
Taxes accrued. . . . . . . . . . . . . . . . .
16,909 (1,285) 20,318
Other (net) . . . . . . . . . . . . . . . . .
(5,022) 14,566 (6,443)
Certain changes in noncurrent assets and
noncurrent liabilities. . . . . . . . . . . . . .
(137,571) 28,879 (13,485)
Other (net) . . . . . . . . . . . . . . . . . .
(446) 250 206

_________ _________ _________
Net cash provided by operating activities . . . . . . .
470,949 405,357 497,879

_________ _________ _________

CASH FLOWS USED IN INVESTING ACTIVITIES
Plant construction and other property additions . . . . . . .
(333,056) (437,375) (483,562)
Proceeds from dispositions of property,
plant and equipment (net) . . . . . . . . . . . . . .
4,716 18,148 59,261
Cost of other investments (net). . . . . . . . . . . . .
(567) (1,949) (8,870)

_________ _________ _________
Net cash used in investing activities. . . . . . . . .
(328,907) (421,176) (433,171)

_________ _________ _________

CASH FLOWS PROVIDED BY (OR USED IN) FINANCING ACTIVITIES
Proceeds from issuance of common stock . . . . . . . . . .
13,066 207,158 6,738
Proceeds from issuance of debentures . . . . . . . . . . .
295,098 148,175 -
Purchase of debentures. . . . . . . . . . . . . . . .
(283,208) (134,918) (23,228)
Borrowings (or repayments) under credit agreement (net). . . . .
- - (66,000) 66,000
Commercial paper borrowings (net) . . . . . . . . . . . .
(5,015) 38,181 (24,252)
Dividends paid on common stock . . . . . . . . . . . . .
(178,125) (168,524) (163,079)
Other (net) . . . . . . . . . . . . . . . . . . .
(91) 10,092 28,120

_________ _________ _________
Net cash provided by (or used in) financing activities . . .
(158,275) 34,164 (109,701)

_________ _________ _________
Net increase (or decrease) in cash and
temporary cash investments. . . . . . . . . . . .
(16,233) 18,345 (44,993)

CASH AND TEMPORARY CASH INVESTMENTS AT JANUARY 1 . . . . . . .
43,355 25,010 70,003

_________ _________ _________
CASH AND TEMPORARY CASH INVESTMENTS AT DECEMBER 31 . . . . . .
$ 27,122 $ 43,355 $ 25,010

========= ========= =========

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid for
Interest (net of amounts capitalized) . . . . . . . . . .
$ 92,880 $ 96,029 $ 96,688
Income taxes (net of refunds). . . . . . . . . . . . .
$ 109,998 $ 35,238 $ 13,510
_______________________________________________________________________________
_______________________________________
The Notes to Consolidated Financial Statements are an integral part of this
statement.

52

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 Company) and subsidiaries within this
framework are summarized in this Note.

PRINCIPLES OF CONSOLIDATION
The Company owns all of the capital stock of its subsidiaries. The
consolidated financial statements represent the accounts of the Company and its
subsidiaries 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
investments where the subsidiary is not able to influence the business policies
of the investee, 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 certain gas costs incurred, including take-or-pay and
transportation costs, and the amount of such costs included in current rates.
Amounts deferred are recognized as purchased gas costs in future periods when
such costs are recovered through adjusted rates.

HEDGING AND OTHER ENERGY PRICE MANAGEMENT ACTIVITIES
The nonregulated subsidiaries utilize natural gas and crude oil futures
contracts to hedge a portion of their transactions against the risk of market
price fluctuations. Gains and losses on these contracts are deferred and
subsequently recognized in the period the related hedged transaction occurs.
Cash flows from hedging transactions are included in the Consolidated Statement
of Cash Flows as an operating activity -- the same category as the cash flows
from the transaction being hedged.

The nonregulated subsidiaries, on occasion, enter into price swap agreements to
modify their exposure to natural gas price risk. Under these agreements, the
subsidiaries receive payments from, or make payments to, counterparties
generally based on the difference between fixed and variable gas prices
specified in the contracts. Settlement takes place under the agreements on a
monthly basis, and amounts received or paid are recognized as an adjustment to
nonregulated gas sales revenues.

PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION
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.

53

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

GAS AND OIL PRODUCING ACTIVITIES
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.

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, including 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.

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The subsidiaries subject to cost-of-service rate regulation capitalize the
estimated costs of equity funds and/or borrowed 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
recorded.

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: 1991 - 5% to 9 3/8%; 1992 - 3 7/8% to 9 1/4% and
1993 - 3 1/4% to 8 7/8%. 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 deferred where required by
regulatory authorities are being amortized as credits to income over the
estimated service lives of the related properties.

CHANGE IN ACCOUNTING
Effective January 1, 1993, the Company adopted the provisions of Statement of
Financial Accounting Standards (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.
Under SFAS No. 109, deferred tax liabilities and assets are recognized for the
expected future tax consequences attributable to temporary differences between
the carrying amounts of assets and liabilities and their tax bases. In
addition, such deferred tax asset and liability amounts are adjusted for the
effects of enacted changes in tax laws or rates. Under the previous income tax
accounting principle, deferred income taxes were generally provided for the tax
effects of timing differences between the recognition of revenue and expense
for income tax purposes and financial reporting purposes. Once recognized, tax
balances were not adjusted for subsequent changes in tax laws or rates.

54

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

SFAS No. 109 also requires the recognition of additional deferred tax
liabilities and assets for timing differences on which deferred tax treatment
had been prohibited in the past by regulatory authorities. Regulatory assets
and liabilities corresponding to such additional deferred taxes, representing
future amounts collectible from or refundable to customers through the rate-
making process, may also be recorded.

The cumulative effect on years prior to 1993 of applying SFAS No. 109 increased
1993 net income by $17,422,000, or $.19 per share. This cumulative effect
adjustment resulted primarily from the reduction in deferred income tax
balances associated with the Company's nonregulated activities. The
application of SFAS No. 109 had no effect on reported pretax earnings.

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.

In accordance with the requirements of Statement of Financial Accounting
Standards No. 87, "Employers' Accounting for Pensions," Consolidated has
recognized a liability for the unfunded accumulated benefit obligation relating
to its supplemental pension benefit plans. An amount equal to the liability,
less a required reduction in common stockholders' equity, net of applicable
deferred taxes, has also been recognized as an intangible asset. Such amounts
recognized are subject to future revision based on both changes in assumptions
and changes in the financial status of the supplemental pension benefit plans.

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 from System companies 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.

CHANGE IN ACCOUNTING
As required, Consolidated adopted Statement of Financial Accounting Standards
No. 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," effective January 1, 1993. This standard required a change from the
practice of recognizing such costs on a pay-as-you-go basis to an accrual
method. Under the standard, the estimated future costs of providing
postretirement benefits are recognized as an expense and a corresponding
liability during the employees' service periods. For the current contributory
postretirement medical plans, the calculations under SFAS No. 106 anticipate
future changes in cost-sharing that are included in the written plan.

55

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As permitted by the standard, the Company elected to amortize the accumulated
postretirement benefit obligation existing at the date of adoption (transition
obligation) over a 20-year period. Prior to 1993, amounts paid for
postretirement benefits were recognized as an expense in the period paid.

FASB STATEMENT NO. 112
In November 1992, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 112, "Employers' Accounting for
Postemployment Benefits." This Statement covers benefits such as salary
continuation, severance pay and disability-related benefits provided to
inactive and former employees prior to retirement. The standard requires the
accrual of a liability for the postemployment benefit obligations if certain
specified conditions are met. Statement No. 112 is effective for fiscal years
beginning after December 15, 1993. Based on management's current estimates and
assumptions, the adoption of the standard is not expected to have a material
effect on Consolidated's financial position, results of operations or cash
flows.

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 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 included in income when realized.

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.

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. Such temporary cash investments are stated at cost, which approximates
fair value due to their short maturities. For purposes of the Consolidated
Statement of Cash Flows, temporary cash investments are considered to be cash
equivalents.

56

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. LINE OF BUSINESS
Total operating revenues of the subsidiaries are derived from their operations
in all phases of the natural gas business. Operations are conducted
principally in the United States with CNG Producing also owning a working
interest in a heavy oil program in Alberta, Canada.

A substantial portion of total operating revenues and related accounts
receivable are generated by the Company's distribution and transmission
subsidiaries. The distribution subsidiaries sell gas and/or provide
transportation services to residential, commercial and industrial customers in
Ohio, Pennsylvania, Virginia and West Virginia. These subsidiaries require
deposits from certain customers to obtain utility services. The transmission
subsidiary 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.

3. 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 $52,115,000 and
$17,777,000 at December 31, 1992 and 1993, including interest. These amounts
are reported in the Consolidated Balance Sheet under "Estimated rate
contingencies and refunds" together with $27,271,000 and $39,679,000,
respectively, which are primarily refunds received from suppliers and
refundable to customers under regulatory procedures.

Pursuant to a November 1993 order from the Federal Energy Regulatory Commission
(FERC), in December 1993, CNG Transmission billed its customers, including
certain affiliates, $177.9 million, which represented the balance of its
unrecovered purchased gas costs and unrecovered sales-related transportation
costs existing at October 1, 1993 -- the date CNG Transmission's restructured
services under FERC Order 636 became effective. Of the $177.9 million removed
from unrecovered gas costs, $75,292,000 is included in the Consolidated Balance
Sheet at December 31, 1993, under "Deferred charges and other noncurrent
assets" representing the distribution subsidiaries' portion of such billing.
The subsidiaries are pursuing the recovery of these costs in state regulatory
proceedings.

In addition, at December 31, 1993, an estimated liability and a corresponding
regulatory asset amounting to $6,300,000 have been recorded by the distribution
subsidiaries for their portion of FERC Order 636 transition costs expected to
be billed by nonaffiliated upstream pipeline companies. This liability
reflects an estimate of these pipeline companies' unrecovered gas costs
approved for billing by the FERC. Additional amounts are likely to be accrued
in the future by the distribution subsidiaries for gas supply realignment costs
and other Order 636 transition costs once these pipeline companies receive
final FERC approval to recover these costs. Based on the pipeline companies'
filings with the FERC, the distribution subsidiaries currently estimate that
their portion of such costs could be in the range of $75 million. However,
since settlement negotiations and regulatory proceedings regarding these costs
are still in progress, the ultimate amount billed may vary significantly from
this estimate.

Based on the nature of the costs and the past rate-making treatment of similar
costs, management believes that the distribution subsidiaries should generally
be able to pass through all Order 636 transition costs to their customers.

57

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION
Total provisions for depreciation of property, plant and equipment for the
years ended December 31, 1991 through 1993, including amounts charged to
accounts other than "Depreciation and amortization" in the Consolidated
Statement of Income, were equivalent to approximately 4.8%, 4.3% and 4.2%,
respectively, of the average capitalized investment subject to depreciation and
amortization in those periods.

Amortization of capitalized costs under the full cost method of accounting for
Consolidated's exploration and production operations amounted to $1.16 per Mcf
(thousand cubic feet) equivalent of gas and oil produced in 1991, $1.19 in
1992, and $1.18 in 1993.

Costs of unproved properties capitalized under the full cost method of
accounting that are excluded from amortization at December 31, 1993, and the
years in which such excluded costs were incurred, follow:
______________________________________________________________________________
DECEMBER 31, Incurred in Calendar Year
1993 1993 1992 1991 Prior
______________________________________________________________________________
(In Thousands)
Property acquisition costs $ 28,920 $ 5,772 $ 1,358 $ 3,902 $ 17,888
Exploration costs . . . 41,002 14,161 6,993 7,659 12,189
Capitalized interest . . 38,641 890 1,485 5,380 30,886
________ ________ ________ ________ ________
Total . . . . . $108,563 $ 20,823 $ 9,836 $ 16,941 $ 60,963
======== ======== ======== ======== ========
______________________________________________________________________________

There are no significant properties, as defined by the SEC, excluded from
amortization at December 31, 1993. 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.

5. PENSION COSTS
Pension expense (or credits), which includes the costs of defined benefit
pension plans and pension supplements, was $822,000, $(1,697,000) and
$(4,844,000), respectively, for the years ended December 31, 1991 through 1993.
The net pension costs, which were determined by an independent actuary,
included the following components:
______________________________________________________________________________
Years Ended December 31, 1993 1992 1991
______________________________________________________________________________
(In Thousands)
Service cost - benefits earned during the period $ 27,266 $ 26,435 $ 26,275
Interest cost on projected benefit obligation . 56,834 54,748 53,713
Return on plan assets . . . . . . . . . (89,441) (73,754) (183,902)
Net amortization and deferral . . . . . . (303) (9,926) 103,936
Special voluntary retirement programs. . . . 800 800 800
________ ________ ________
Net pension cost . . . . . . . . . $ (4,844) $ (1,697) $ 822
======== ======== ========
______________________________________________________________________________

58

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 began October 1, 1990, in accordance with the rate-making
treatment approved by the Pennsylvania Public Utility Commission. The amount
amortized to pension expense was $800,000 in each of the years ended December
31, 1991 through 1993.

The following table sets forth the funded status of the plans, as determined by
an independent actuary, at December 31, 1992 and 1993:

_______________________________________________________________________________
_____________________
Plans Where Assets
Plans Where
Exceed Accumulated
Accumulated Benefits
Benefits
Exceed Assets
December 31, 1993 1992
1993 1992
_______________________________________________________________________________
_____________________
(In
Thousands)

Actuarial present value of:
Vested benefit obligation . . . . . . $ 656,308 $ 630,179
$ 15,728 $ 17,747
========== ==========
======== ========
Accumulated benefit obligation . . . . $ 683,559 $ 653,848
$ 15,728 $ 17,747
========== ==========
======== ========
Projected benefit obligation . . . . . $ 918,079 $ 879,651
$ 15,728 $ 17,747
Plan assets at fair value. . . . . . . 1,190,909 1,143,876
- - -
__________ __________
________ ________
Plan assets in excess of (or less than)
projected benefit obligation . . . . . 272,830 264,225
(15,728) (17,747)
Unrecognized net loss (or gain). . . . . (170,333) (165,599)
2,495 3,004
Unrecognized net obligation (or asset) . . (95,940) (105,260)
3,780 5,590
Unrecognized prior service cost (or benefit) 7,535 11,410
3,792 4,518
Recognition of minimum liability . . . . - -
(10,067) (13,112)
__________ __________
________ ________
Prepaid pension cost (or pension liability)
recognized in the Consolidated
Balance Sheet . . . . . . . . . $ 14,092 $ 4,776
$(15,728) $(17,747)
========== ==========
======== ========
_______________________________________________________________________________
_____________________

The projected benefit obligation at December 31, 1992 and 1993, was determined
using an annual discount rate of 6.5% 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 recognized relating to the Company's supplemental pension
benefit plans amounted to $13,112,000 and $10,067,000 at December 31, 1992 and
1993. The related intangible asset recognized as of those dates amounted to
$10,108,000 and $7,572,000, respectively. These amounts are included in the
Consolidated Balance Sheet under "Other deferred credits and noncurrent
liabilities" and "Deferred charges and other noncurrent 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
$216,000 and $361,000 at December 31, 1992 and 1993, respectively.

59

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. OTHER POSTRETIREMENT BENEFITS
Effective January 1, 1993, the Company adopted the provisions of Statement of
Financial Accounting Standards No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions." Statement No. 106 requires that
the estimated future costs of providing postretirement benefits, such as health
care and life insurance, be recognized as an expense and a liability during the
employees' service periods. As permitted under the standard, the Company
elected to amortize the accumulated postretirement benefit obligation existing
at the date of adoption (transition obligation) of $288,393,000 over a 20-year
period.

Net periodic postretirement benefit cost for the year ended December 31, 1993,
as determined by an independent actuary, included the following components:
______________________________________________________________________________
Year Ended December 31, 1993
______________________________________________________________________________
(In Thousands)
Service cost - benefits attributed to service during the period $10,549
Interest cost on accumulated postretirement benefit obligation 23,208
Amortization of transition obligation. . . . . . . . . 14,420
_______
Net periodic postretirement benefit cost . . . . . . . $48,177
=======
______________________________________________________________________________

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, 1993:
______________________________________________________________________________
December 31, 1993
______________________________________________________________________________
(In Thousands)
Accumulated postretirement benefit obligation:
Retirees. . . . . . . . . . . . . . . . . . $ 165,819
Fully eligible active plan participants . . . . . . . 58,465
Other active plan participants . . . . . . . . . . 102,900
_________
Total accumulated postretirement benefit obligation. . . 327,184
Plan assets at fair value. . . . . . . . . . . . . -
_________
Accumulated postretirement benefit obligation
in excess of plan assets . . . . . . . . . . . (327,184)
Unrecognized net loss . . . . . . . . . . . . . . 22,821
Unrecognized transition obligation. . . . . . . . . . 273,973
_________
Accrued postretirement benefit cost recognized in the
Consolidated Balance Sheet . . . . . . . . . . $ (30,390)
=========
______________________________________________________________________________

The weighted average discount rate used in determining the accumulated
postretirement benefit obligation was 7.25%. The average assumed annual rate
of salary increase for the applicable life insurance plans was 5.5%.

The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation for the medical plans is 11% for 1994,
declining gradually to 5% 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,
1993, would be increased by $28.8 million. A 1% change would also increase the
aggregate of the service and interest cost components of net periodic
postretirement benefit cost for 1993 by $4.2 million.

60

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The majority of the estimated postretirement benefit costs and of the
transition obligation is attributable to Consolidated's rate-regulated
subsidiaries. Accordingly, these subsidiaries are seeking, or intend to seek
as soon as practicable, rate relief from their respective regulatory
commissions for the increased level of expense resulting from the adoption of
the standard. In this regard, regulatory authorities having jurisdiction over
the Company's subsidiaries have indicated their intention to generally allow
inclusion in rates of postretirement benefit costs determined on an accrual
basis, subject to prudency and certain other conditions. As a result, the
Company's rate-regulated subsidiaries have generally deferred the differences
between SFAS No. 106 costs and amounts currently included in rates pending
expected recovery of Statement No. 106 costs and related deferrals in
regulatory proceedings. The amount of SFAS No. 106 costs deferred at December
31, 1993, was $27,662,000, which is included in the Consolidated Balance Sheet
under "Deferred charges and other noncurrent assets."

Currently, the subsidiary companies do not prefund postretirement benefit
costs, but pay claims as presented. However, 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.

Prior to the adoption of SFAS No. 106, postretirement benefit costs were
expensed as paid. The cost of such benefits amounted to $16,881,000 and
$17,948,000 for the years ended December 31, 1991 and 1992, respectively.

7. INCOME TAXES
As detailed in Note 1, the Company adopted Statement of Financial Accounting
Standards No. 109, "Accounting for Income Taxes," effective January 1, 1993.
Statement No. 109 required a change from the deferred method to an asset and
liability approach for accounting for and reporting of income taxes. The
cumulative effect on years prior to 1993 of applying SFAS No. 109 increased net
income in 1993 by $17,422,000, or $.19 per share, due primarily to the
reduction in deferred tax balances associated with the Company's nonregulated
activities.

"Income taxes - estimated" included the following:
______________________________________________________________________________
Years Ended December 31, 1993 1992 1991
______________________________________________________________________________
(In Thousands)
Current provision
Federal . . . . . . . . . . $ 99,029 $ 18,378 $ 32,274
State. . . . . . . . . . . 23,279 5,466 3,119
Deferred income taxes (net)
Federal . . . . . . . . . . (6,688) 35,941 15,715
State. . . . . . . . . . . (13,094) 11,529 6,375
Investment tax credit . . . . . . (2,620) (2,691) (2,639)
________ ________ ________
Total. . . . . . . . . . . $ 99,906 $ 68,623 $ 54,844
======== ======== ========
Income before taxes. . . . . . . $288,400 $263,581 $223,457
======== ======== ========
______________________________________________________________________________

61

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

On August 10, 1993, the federal corporate income tax rate was increased from
34% to 35%, retroactive to January 1, 1993. As required by SFAS No. 109,
existing deferred tax assets and liabilities were adjusted to reflect this
enacted tax rate change. As a result, deferred income tax expense was
increased (and operating income was reduced) in the third quarter of 1993 by
$11,429,000, or $.12 per share. In addition, income taxes based on pretax
earnings for the year 1993 increased by $2,692,000, or $.03 per share because
of the higher rate. The total adjustment to the net deferred income tax
liability included in the Consolidated Balance Sheet as a result of the
increase in the federal corporate income tax rate amounted to $26,707,000.

Income taxes charged to operating income differed from the amounts of
$75,975,000, $89,618,000 and $100,940,000 shown in the next table that were
computed by applying the statutory federal income tax rate of 34% (1991 and
1992) and 35% (1993) to reported income before taxes. The reasons for the
differences follow:
______________________________________________________________________________
Years Ended December 31, 1993 1992 1991
______________________________________________________________________________
(In Thousands)
Computed "expected" tax expense. . . . $100,940 $ 89,618 $ 75,975
Increases (or reductions) in tax
resulting from:
Production tax credit . . . . . . (8,435) (7,506) (5,349)
Investment tax credit . . . . . . (2,620) (2,691) (2,639)
Deferred tax reversals . . . . . . - (15,325) (15,803)
State income taxes . . . . . . . 6,620 11,217 6,266
Effect of increase in federal
corporate income tax rate
on deferred income taxes. . . . . 11,429 - -
Miscellaneous. . . . . . . . . (8,028) (6,690) (3,606)
________ ________ ________
Income taxes charged to operating income $ 99,906 $ 68,623 $ 54,844
======== ======== ========

Effective tax rate . . . . . . . 34.6% 26.0% 24.5%
______________________________________________________________________________

62

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The current and noncurrent deferred income taxes reported in the Consolidated
Balance Sheet at December 31, 1993, represent the net expected future tax
consequences attributable to temporary differences between the carrying amounts
of assets and liabilities and their tax bases. These temporary differences and
the related tax effects were as follows:
______________________________________________________________________________
1993
Deferred income Deferred income
December 31, taxes taxes-current
______________________________________________________________________________
(In Thousands)
Deferred tax liabilities:
Excess of tax over book depreciation . . $425,488 $ -
Exploration and intangible well
drilling costs . . . . . . . . . 276,462 -
FERC Order 636 transition costs . . . . 48,404 -
Allowance for funds used
during construction . . . . . . . 41,089 -
Other. . . . . . . . . . . . . 72,695 -
________ _________
Total liabilities . . . . . . . . 864,138 -
________ _________

Deferred tax assets:
Deferred investment tax credits . . . . 20,291 -
Tax basis step-up in connection with
acquisition of subsidiary . . . . . 15,001 -
Overheads capitalized for tax purposes. . 12,240 -
Supplier and other refunds. . . . . . - 13,959
Unrecovered gas costs . . . . . . . - 3,979
Other. . . . . . . . . . . . . 33,095 5,747
Valuation allowance . . . . . . . . - -
________ _________
Total assets. . . . . . . . . . 80,627 23,685
________ _________
Total deferred income taxes. . . . . $783,511 $(23,685)
======== ========
______________________________________________________________________________

A regulatory liability amounting to $72,208,000 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
$113,483,000 has been recorded at December 31, 1993. These regulatory amounts
are included in the Consolidated Balance Sheet under "Other deferred credits
and noncurrent liabilities" and "Deferred charges and other noncurrent assets,"
respectively.

63

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. GAS STORED
Based upon the average price of gas purchased during 1993, the current cost of
replacing the inventory of "Gas stored - current portion" exceeded the amount
stated on a LIFO basis by approximately $176,397,000 at December 31, 1993.

A portion of gas in underground storage used as a pressure base for operations
is included in "Property, Plant and Equipment" in the amounts of $120,270,000
and $123,564,000 at December 31, 1992 and 1993.

9. OTHER ASSETS
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 FASB Statement 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.

LAKEWOOD COGENERATION PROJECT
CNG Energy holds directly a 34% limited partnership interest in Lakewood
Cogeneration, L.P. (Lakewood Partnership), a partnership formed to construct,
own and operate a cogeneration facility in Lakewood, New Jersey. CNG Lakewood,
Inc., a wholly owned subsidiary of CNG Energy, owns a 1% general partnership
interest in the Lakewood Partnership. Using natural gas, the facility will
produce electricity for sale to an electric utility and steam for sale
primarily to customers in an industrial park.

In November 1992, the Lakewood Partnership entered into a credit agreement with
a group of banks and an institutional investor that will provide up to
$262,000,000 in construction financing through non-recourse loans made to the
partnership. A portion of the proceeds from the construction loans was used to
reimburse the partners for certain expenditures previously made in connection
with the project. Construction of the facility began in late 1992 and is
expected to be completed by the end of 1994. At December 31, 1993, CNG
Energy's total investment in the project amounted to $7,186,000.

10. COMMON STOCKHOLDERS' EQUITY
A summary of the changes in stockholders' equity follows:

64

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

_______________________________________________________________________________
_______________________________________
Summary of Changes in Common Stockholders' Equity
_______________________________________________________________________________
_______________________________________
Common Stock Capital in
Excess
Issued of Par Value
Treasury Stock
Number of Value
Retained Number of
Shares at Par Paid-In Other
Total Earnings Shares Cost
_______________________________________________________________________________
_______________________________________
(In Thousands)

Balance at December 31, 1990. . . 87,398 $240,345 $189,656 $40,280
$229,936 $1,411,418 (1,071) $(37,105)
Net income. . . . . . . . . - - - -
- - 168,613 - -
Cash dividends declared
Common stock ($1.885 per share) . - - - -
- - (163,983) - -
Common stock issued
Dividend Reinvestment Plan. . . 105 287 4,062 -
4,062 - - -
Stock options . . . . . . . 67 185 2,204 -
2,204 - - -
Stock awards cancelled . . . . (3) (8) (109) -
(109) - - -
Sale of treasury stock. . . . . - - 4,146 -
4,146 - 686 24,167
Reissuance of treasury stock
Stock Incentive Plan. . . . . - - 935 -
935 - 118 4,222
Employee Stock Ownership Plan. . - - 207 -
207 - 22 733
Pension liability adjustment. . . - - - -
- - (472) - -
______ ________ ________ _______
________ __________ ______ ________
Balance at December 31, 1991. . . 87,567 240,809 201,101 40,280
241,381 1,415,576 (245) (7,983)
Net income. . . . . . . . . - - - -
- - 194,958 - -
Cash dividends declared
Common stock ($1.905 per share) . - - - -
- - (171,473) - -
Common stock issued
Public offering . . . . . . 4,600 12,650 180,962 -
180,962 - - -
Stock options . . . . . . . 113 312 3,688 -
3,688 - - -
Employee Stock Ownership Plan
and Dividend Reinvestment Plan. 107 295 4,401 -
4,401 - - -
System Thrift Plans . . . . . 105 289 4,561 -
4,561 - - -
Stock awards . . . . . . . 65 177 2,137 -
2,137 - - -
Purchase of treasury stock . . . - - - -
- - - (95) (3,481)
Sale of treasury stock. . . . . - - 1,894 -
1,894 - 339 11,436
Reissuance of treasury stock under
Stock Incentive Plan. . . . . - - 5 -
5 - 1 28
Pension liability adjustment (Note 5) - - - -
- - 216 - -
______ ________ ________ _______
________ __________ ______ ________
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 - - -
Dividend Reinvestment Plan. . . 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 (Note 5) - - - -
- - 361 - -
______ ________ ________ _______
________ __________ ______ ________
Balance at December 31, 1993. . . 92,934 $255,568 $413,801 $40,280
$454,081 $1,466,783 - $ -
====== ======== ======== =======
======== ========== ====== ========
_______________________________________________________________________________
_______________________________________

65

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

COMMON STOCK OFFERING
In September 1992, the Company issued, through a public offering, 4,600,000
shares of its common stock at a price to the public of $43.50 per share. The
net proceeds of the offering, after deducting the underwriting discount and
expenses, were $193,612,000. The proceeds from the stock sale were used to
finance capital expenditures of the subsidiaries.

UNISSUED SHARES
At December 31, 1993, 107,066,172 shares of common stock were unissued. Of
these, a total of 18,436,115 shares have been registered with the SEC for
possible issuance under various employee benefit plans including the 1991 Stock
Incentive Plan, the Long-Term Incentive Plan and the System Thrift Plans.
Shares acquired by these plans can consist of original issue shares, treasury
shares or shares purchased in the open market. In addition, 741,356 shares
have been registered with the SEC for possible issuance to shareholders under
the Dividend Reinvestment Plan and 4,629,629 shares have been 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
through December 31, 1995. 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.

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 and its
subsidiaries. The maximum number of shares available for issuance in each
calendar year is determined in accordance with a formula contained in the plan.
During 1993, 3,056,107 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.

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.

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, 1993, no stock appreciation rights
have been granted under the plan.

66

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

LONG-TERM INCENTIVE PLAN
The Company's 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.

Shares of common stock issued as restricted stock awards under the plan are
held by the Company until certain restrictions lapse, which ordinarily occurs
equally on the third through sixth award anniversaries. The market value of
the stock when awarded is recorded as compensation expense over the six-year
period.

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.

A summary of stock option activity under both plans for the years ended
December 31, 1991 through 1993, follows:
_______________________________________________________________________________
Number Option Price
of Shares Per Share
_______________________________________________________________________________
(In Thousands)
Shares under option:
At January 1, 1991 . . . . . . . 843 $32.50 - $50.75
Granted in 1991 . . . . . . . . 509 $41.13 - $43.88
Exercised in 1991. . . . . . . . (67) $34.38 - $40.00
Cancelled in 1991. . . . . . . . (59) $34.38 - $50.75
_____
At December 31, 1991. . . . . . . 1,226 $32.50 - $50.75

Granted in 1992 . . . . . . . . 659 $34.75 - $47.25
Exercised in 1992. . . . . . . . (113) $34.38 - $44.00
Cancelled in 1992. . . . . . . . (59) $34.38 - $50.75
_____
At December 31, 1992. . . . . . . 1,713 $32.50 - $50.75

Granted in 1993 . . . . . . . . 552 $44.88 - $55.00
Exercised in 1993. . . . . . . . (238) $33.25 - $50.75
Cancelled in 1993. . . . . . . . (65) $34.75 - $50.75
_____
At December 31, 1993. . . . . . . 1,962 $32.50 - $55.00
=====
_______________________________________________________________________________

At December 31, 1993, options were exercisable for the purchase of 295,077
shares. Stock options become exercisable for the purchase of 381,164 shares in
1994, 456,311 in 1995, 402,394 in 1996, and 426,618 shares thereafter.

67

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, 1992 and 1993.

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), $664,756,000 of consolidated retained earnings was free from such
restrictions at December 31, 1993. The indenture also imposes dividend
limitations on the subsidiaries, but at December 31, 1993, these limitations
did not restrict their ability to pay dividends to the Company.

13. LONG-TERM DEBT
Long-term debt, excluding current maturities, follows:
______________________________________________________________________________
December 31, 1993 1992
______________________________________________________________________________
(In Thousands)
Debentures
6 5/8%, Due December 1, 2013 . . . . . . $ 150,000 $ -
5 3/4%, Due August 1, 2003. . . . . . . 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 . . . . . . 100,000 100,000
7 5/8%, Due April 1, 1996 . . . . . . . - 100,000
8 1/8%, Due June 1, 1997 . . . . . . . - 18,600
8 3/8%, Due September 1, 1996. . . . . . - 13,900
9 1/4%, Due July 1, 1995 . . . . . . . - 12,500
8 5/8%, Due March 1, 1999 . . . . . . . - 20,000
7 3/4%, Due June 1, 1998 . . . . . . . - 18,000
7 5/8%, Due May 1, 1997. . . . . . . . - 16,000
7 3/4%, Due October 1, 1996 . . . . . . - 7,000
8 3/8%, Due May 1, 1996. . . . . . . . - 11,200
7 7/8%, Due December 1, 1995 . . . . . . - 10,800
9%, Due July 1, 1995. . . . . . . . . - 9,600
8 1/4%, Due November 1, 1994 . . . . . . - 6,000
7 3/4%, Due July 1, 1994 . . . . . . . - 6,000
Unamortized debt discount, less premium . . (9,252) (5,413)
Convertible Subordinated Debentures
7 1/4%, Due December 15, 2015. . . . . . 250,000 250,000
Unamortized debt discount . . . . . . . (2,100) (2,231)
9.94% Unsecured loan due January 1, 1999. . . 20,000 20,000
__________ __________
Total . . . . . . . . . . . . . $1,158,648 $1,111,956
========== ==========
______________________________________________________________________________

The estimated fair value of the Company's debentures, including current
maturities, was $1,208,719,000 and $1,235,351,000 at December 31, 1992 and
1993. Fair value was estimated based on closing transactions and/or quotations
for the Company's debentures as of those dates.

68

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

There are no debentures maturing in the years 1994 and 1995. The aggregate
principal amounts of the Company's debentures maturing in the years 1996
through 1998 are: $6,250,000; $106,250,000 and $156,250,000.

Discounts and premiums and the expenses incurred in connection with the
issuance of debentures are being amortized on a basis which will equitably
distribute the net 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 to be repaid in five annual
installments of $4,000,000 each, beginning January 1, 1995, has been guaranteed
by the Company.

In March 1991, the Company entered into a credit agreement with a group of
banks that provides for the borrowing of up to $300,000,000. The 1991 Credit
Agreement initially was to expire on March 31, 1994; however, each year the
term of the agreement has, with the approval of the banks, been extended for a
period of one additional year. In February 1994, the term was extended to
March 31, 1997. The loans under the 1991 Credit Agreement 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 prepaid 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. A commitment fee
of 1/8 of 1% per annum is charged under the 1991 Credit Agreement. No
revolving credit loans were outstanding at December 31, 1992 or 1993.

14. SHORT-TERM BORROWINGS
The weighted average interest rate on the Company's $455,000,000 of commercial
paper notes outstanding at December 31, 1993, was 3.35%. Because of the short
maturities of commercial paper notes, the carrying amount represents a
reasonable estimate of fair value.

Commercial paper notes are supported by unused lines of credit totaling
$475,000,000. These lines may be used if the sale of commercial paper is not
feasible. Each of the lines bears a commitment fee, but such fees, in the
aggregate, are not significant. In addition to these credit lines, the Company
may utilize unused portions of its 1991 Credit Agreement to provide support for
commercial paper notes.

There are no agreements or arrangements requiring compensating balances with
respect to either lines of credit or outstanding bank loans. Under the
Company's policy, bank deposits are maintained for normal operating purposes.

69

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15. ENVIRONMENTAL MATTERS
The Company and its subsidiaries are 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 Company and
its subsidiaries, or their predecessors.

As part of their normal business operations, the subsidiaries periodically
monitor their properties and facilities and resolve potential environmental
matters so as to remain in compliance with the various environmental laws and
regulations. The Company also conducts general environmental surveys on a
continuing basis at its operating facilities to assure compliance with these
laws and regulations. In this regard, voluntary surveys at subsidiary meter
sites were conducted to determine the extent of any possible soil contamination
due to mercury spillage. These studies, which are continuing, are not in
response to any governmental or regulatory directive, order or settlement
agreement and have not disclosed any mercury contamination for which the
remediation costs would be considered material to Consolidated's financial
position, results of operations or cash flows. 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. It is unknown at this
time whether civil penalties will be assessed. Pursuant to the Order and
Agreement, CNG Transmission is performing certain sampling, testing and
analysis, and conducting a program of remediation at some of its Pennsylvania
facilities. Total remediation costs in connection with the Order and Agreement
are not expected to be material with respect to Consolidated's financial
position, results of operations or cash flows. Based on current knowledge, the
Company has recognized a gross estimated liability amounting to $19,661,000 at
December 31, 1993, for future costs expected to be incurred to remediate or
mitigate hazardous substances at mercury sites and at facilities covered by the
Order and Agreement. The estimate for this liability was based on current
environmental laws and regulations and existing technology.

Inasmuch as certain environmental-related expenditures are expected to be
recoverable in future regulatory proceedings, a regulatory asset amounting to
$11,378,000 at December 31, 1993, is included in the Consolidated Balance Sheet
under the caption "Deferred charges and other noncurrent assets." Also,
uncontested claims amounting to $3,566,000 at December 31, 1993, were
recognized for environmental-related costs probable of recovery through joint-
interest operating agreements.

The total amounts included in operating expenses for remediation and other
environmental-related costs were $3,205,000, $7,646,000, and $9,049,000,
respectively, for the years ended December 31, 1991 through 1993. The
components of such costs are as follows:
______________________________________________________________________________
Years Ended December 31, 1993 1992 1991
______________________________________________________________________________
(In Thousands)
Recurring costs for ongoing operations $3,381 $4,032 $1,601
Mandated remediation and other
compliance costs . . . . . . . 3,963 2,816 1,493
Voluntary remediation costs . . . . 1,185 703 4
Other . . . . . . . . . . . 520 95 107
______ ______ ______
Total. . . . . . . . . . . $9,049 $7,646 $3,205
====== ====== ======
______________________________________________________________________________

The Company's environmental-related capital expenditures for monitoring or
complying with laws and regulations for 1991 through 1993 were not material.

70

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Company has determined that it is associated with 16 former manufactured
gas plant sites, five of which are currently owned by the Company. 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 exact nature of environmental issues that 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.

16. 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 1991 through 1993 was not material, and future rental
payments required under leases in effect at December 31, 1993, are not
material.

CNG Transmission and certain of the Company's distribution subsidiaries are
subject to the Federal Clean Air Act and the Federal Clean Air Act Amendments
of 1990 (1990 amendments) which added significantly to the existing
requirements established by the Federal Clean Air Act. These subsidiaries
operate compressor stations that are covered by the new nitrogen oxide emission
standard established as a result of the 1990 amendments. The Company will have
until May 31, 1995, to comply with the emission standard. The Company expects
that compliance will require significant capital expenditures to modify the
compressor engines along the Company's pipeline system. However, the actual
cost of compliance will be dependent upon the requirements imposed by the
environmental agencies of the states in which the compressor stations are
located. Based on the Company's preliminary estimates and analyses,
approximately $46 million of capital expenditures may be required. Actual
capital expenditures required to comply with the 1990 amendments are expected
to be recoverable through future regulatory proceedings. Reference is made to
Note 15 for additional information on environmental matters.

It is estimated that Consolidated's 1994 capital budget will amount to
$439,600,000, and that approximately $153,000,000 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 Consolidated's financial position, results of operations or
cash flows.

71

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. 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 Statement of Financial
Accounting Standards 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:
_______________________________________________________________________________
December 31, 1993 1992
_______________________________________________________________________________
(In Thousands)
Capitalized costs of
Proved properties. . . . . . . . . $2,685,856 $2,673,042
Unproved properties . . . . . . . . 232,312 194,189
__________ __________
Total . . . . . . . . . . . . $2,918,168 $2,867,231
========== ==========

Accumulated depreciation of
Proved properties. . . . . . . . . $1,723,113 $1,609,850
Unproved properties . . . . . . . . 78,352 68,444
__________ __________
Total . . . . . . . . . . . . $1,801,465 $1,678,294
========== ==========
_______________________________________________________________________________

TOTAL COSTS INCURRED
The following costs were incurred by subsidiaries in their gas and oil
producing activities during the years 1991 through 1993:
_______________________________________________________________________________
Years Ended December 31, 1993 1992 1991
_______________________________________________________________________________
(In Thousands)
Property acquisition costs
Proved properties. . . . . . . . . $ 132 $ 7,926 $ -
Unproved properties . . . . . . . . 18,224 14,378 20,879
________ ________ ________
Subtotal . . . . . . . . . . . 18,356 22,304 20,879
Exploration costs . . . . . . . . . 47,934 30,860 30,420
Development costs . . . . . . . . . 40,516 42,059 63,413
________ ________ ________
Total . . . . . . . . . . . . $106,806 $ 95,223 $114,712
======== ======== ========
_______________________________________________________________________________

72

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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. Consolidated
cautions that these standardized disclosures do not represent 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.

______________________________________________________________________________
Years Ended December 31, 1993 1992 1991
______________________________________________________________________________
(In Thousands)
Revenues (net of royalties) from:
Sales to unaffiliated companies . . . $204,614 $155,481 $187,662
Transfers to other operations. . . . 88,241 135,280 110,351
________ ________ ________
Total . . . . . . . . . . . 292,855 290,761 298,013
________ ________ ________
Less: Production (lifting) costs . . . 49,177 55,281 58,253
Depreciation and amortization . . 173,171 176,463 183,027
Income tax expense. . . . . . 18,400 13,509 20,144
________ ________ ________
Results of operations . . . . . . . $ 52,107 $ 45,508 $ 36,589
======== ======== ========
______________________________________________________________________________

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, 1991 through 1993, and changes
in the reserves during those years, are shown in the two schedules which
follow:
______________________________________________________________________________
Years Ended December 31, 1993 1992 1991
______________________________________________________________________________
(In Bcf)
PROVED DEVELOPED AND UNDEVELOPED RESERVES* - GAS
At January 1 . . . . . . . . . . . 918 918 1,017
Changes in reserves
Revisions of previous estimates . . . . 46 (23) (17)
Purchases of gas in place . . . . . . - 19 -
Extensions, discoveries and other additions 55 141 79
Production . . . . . . . . . . . (124) (121) (126)
Sales of gas in place. . . . . . . . (10) (16) (35)
_____ _____ _____
At December 31. . . . . . . . . . . 885 918 918
===== ===== =====

PROVED DEVELOPED RESERVES* - GAS
At January 1 . . . . . . . . . . . 794 855 920
At December 31. . . . . . . . . . . 761 794 855

* Net before royalty.
______________________________________________________________________________

Included in the caption "Extensions, discoveries and other additions" for 1992
are 79 Bcf 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, 1991 through 1993, include United States reserves of
917, 917 and 884 Bcf which, together with the Canadian reserves and the gas
reserves reported under "Cost-of-Service Properties," are as contained in
reports of Ralph E. Davis Associates, Inc., independent geologists.

73

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
______________________________________________________________________________
Years Ended December 31, 1993 1992 1991
______________________________________________________________________________
(In Thousand Bbls)
Proved developed and undeveloped reserves* - Oil
At January 1 . . . . . . . . . . . 29,238 31,014 37,881
Changes in reserves
Revisions of previous estimates . . . . 290 390 (3,300)
Purchases of oil in place . . . . . . - 245 -
Extensions, discoveries and other additions 1,978 2,104 3,410
Production . . . . . . . . . . . (3,907) (4,508) (5,246)
Sales of oil in place. . . . . . . . (3) (7) (1,731)
______ ______ ______
At December 31. . . . . . . . . . . 27,596 29,238 31,014
====== ====== ======

Proved developed reserves* - Oil
At January 1 . . . . . . . . . . . 27,449 30,070 36,541
At December 31. . . . . . . . . . . 21,936 27,449 30,070

* Net before royalty.
______________________________________________________________________________

The foregoing proved developed and undeveloped oil reserves at December 31,
1991 through 1993, include United States reserves of 25,623, 23,493 and 21,917
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.
______________________________________________________________________________
December 31, 1993 1992 1991
______________________________________________________________________________
(In Thousands)
Future cash inflows . . . . . . . . $2,336,553 $2,421,422 $2,570,408
Less: Future development
and production costs . . . . . 529,592 572,576 496,389
Future income tax expense. . . . 537,966 473,475 608,264
__________ __________ __________
Future net cash flows . . . . . . . 1,268,995 1,375,371 1,465,755
Less annual discount (10% a year) . . . 500,732 557,019 584,624
__________ __________ __________
Standardized measure of discounted future
net cash flows . . . . . . . . . $ 768,263 $ 818,352 $ 881,131
========== ========== ==========
______________________________________________________________________________

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
flows, less the tax basis of the properties involved, and giving effect to tax
deductions, or permanent differences and tax credits.

74

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

It is not intended that the FASB's standardized measure of discounted future
net cash flows represent the fair market value of Consolidated'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.

_______________________________________________________________________________
________________________
Years Ended December 31, 1993
1992 1991
_______________________________________________________________________________
________________________

(In Thousands)

Standardized measure of discounted future net
cash flows at January 1. . . . . . . . . . . . $ 818,352
$ 881,131 $1,078,866
Changes in the year resulting from
Sales and transfers of gas and oil produced
during the year, less production costs . . . . . .
(243,678) (235,480) (239,760)
Prices and production and development costs
related to future production . . . . . . . . . 12,635
(70,092) (65,746)
Extensions, discoveries and other additions,
less production and development costs . . . . . . 99,662
108,734 108,528
Previously estimated development costs
incurred during the year. . . . . . . . . . . 4,838
24,914 17,220
Revisions of previous quantity estimates . . . . . . 66,506
(66,504) (24,810)
Accretion of discount . . . . . . . . . . . . 109,287
123,976 147,706
Income taxes . . . . . . . . . . . . . . .
(41,395) 84,126 39,556
Purchases and sales of proved reserves in place (net). .
(5,439) 17,548 (29,545)
Other (principally timing of production) . . . . . .
(52,505) (50,001) (150,884)
_________
__________ __________
Standardized measure of discounted future net
cash flows at December 31 . . . . . . . . . . . $ 768,263
$ 818,352 $ 881,131
=========
========== ==========
_______________________________________________________________________________
________________________

COST-OF-SERVICE PROPERTIES
As previously stated, activities subject to cost-of-service rate regulation are
excluded from the foregoing information. At December 31, 1992 and 1993, net
capitalized costs of cost-of-service properties amounted to $30,645,000 and
$27,320,000, respectively. Related proved reserves of gas and oil are located
in the United States, and at December 31, 1991 through 1993, amounted to 87, 80
and 75 Bcf of gas and 313, 283 and 287 thousand barrels of oil, respectively.
Production for the years 1991 through 1993 amounted to 7, 7 and 6 Bcf of gas
and 33, 31 and 29 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.

75

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 1992 and 1993
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
Consolidated. Seasonal fluctuations are further influenced by the timing of
price relief granted under regulation to compensate for certain past cost
increases.

_______________________________________________________________________________
_____________________

Quarter
First Second
Third* Fourth
_______________________________________________________________________________
_____________________
(In
Thousands)

1993
Total operating revenues . . . . . . . . $1,131,526 $549,070
$473,348 $1,030,141
Operating income. . . . . . . . . . . 144,904 24,133
(11,389) 99,790
Income before cumulative effect of
change in accounting principle . . . . . 125,714 6,636
(29,965) 86,109
Cumulative effect prior to January 1,
1993, of applying SFAS No. 109 . . . . . 17,422 -
- - -
Net income. . . . . . . . . . . . . 143,136 6,636
(29,965) 86,109
Earnings per share of common stock**
Income before cumulative effect of
change in accounting principle. . . . . 1.36 .07
(.32) .93
Cumulative effect prior to January 1,
1993, of applying SFAS No. 109. . . . . .19 -
- - -
Net income . . . . . . . . . . . . 1.55 .07
(.32) .93

1992
Total operating revenues . . . . . . . . $ 922,528 $448,113
$359,890 $ 790,319
Operating income. . . . . . . . . . . 132,134 19,836
4,062 117,610
Net income. . . . . . . . . . . . . 111,187 564
(13,818) 97,025
Earnings per share of common stock** . . . . 1.27 .01
(.15) 1.05

* Operating income and net income for the 1993 third quarter are reduced to
reflect additional
deferred income taxes of $11,429,000, or $(.12) per share, resulting from
the increase in the
federal corporate income tax rate (see Note 7 to the consolidated financial
statements).
** The sum of the quarterly amounts does not equal the year's amount because
the quarterly
calculations are based on a changing number of average shares outstanding.
_______________________________________________________________________________
_____________________

76

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

(C) COMMON STOCK MARKET PRICES AND RELATED MATTERS
At December 31, 1993, there were 41,648 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 1992 and
1993 follow. Restrictions on the payment of dividends are discussed in Note
12.
______________________________________________________________________________
Quarter
First Second Third Fourth
______________________________________________________________________________
Market Price Range
1993 - High . . . . . . . $49 7/8 $53 5/8 $55 3/8 $53 1/4
- Low. . . . . . . . $43 1/2 $48 5/8 $48 3/8 $42 5/8

1992 - High . . . . . . . $43 1/2 $43 7/8 $48 5/8 $48 3/8
- Low. . . . . . . . $33 5/8 $35 $42 3/8 $44 3/8

Dividends Declared per Share
1993. . . . . . . . . . $.48 $.48 $.48 $.485
1992. . . . . . . . . . $.475 $.475 $.475 $.48
______________________________________________________________________________

77

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (Note 1)

_______________________________________________________________________________
________________________________________

Other Changes - Balance at
Balance at Additions
Add (Deduct) December 31
Classification January 1 at Cost
Retirements (Note 2) (Note 3)
_______________________________________________________________________________
________________________________________

(In Thousands)
Year 1993

Gas utility and other plant
Plant in service . . . . . . . . . . $4,001,044 $ 217,243
$28,480 $ 4,316 $4,194,123
Construction work in progress. . . . . . 51,441 11,376
- - - 62,817
Plant held for future use . . . . . . . 57,254 1,974
93 (724) 58,411
Other property and plant adjustments . . . 47,645 2
2 - 47,645
__________ _________
_______ _________ __________
Total gas utility and other plant . . $4,157,384 $ 230,595
$28,575 $ 3,592 $4,362,996
========== =========
======= ========= ==========

Exploration and production properties
Plant in service
Production plant
Operated acreage. . . . . . . . . $ 342,329 $ 1,709
$ 628 $ (4,749) $ 338,661
Other . . . . . . . . . . . . 2,356,997 54,052
53,354 2,448 2,360,143
Non-roduction plant . . . . . . . . 29,410 3,861
1,021 (226) 32,024
Construction work in progress. . . . . . 4,285 14,071
- - - 18,356
Plant held for future use
Unoperated acreage. . . . . . . . . 191,366 36,961
1,213 2,230 229,344
Other . . . . . . . . . . . . . 5,331 92
918 (1) 4,504
__________ _________
_______ _________ __________
Total exploration and
production properties . . . . . $2,929,718 $ 110,746
$57,134 $ (298) $2,983,032
========== =========
======= ========= ==========
_______________________________________________________________________________
________________________________________
Notes to Schedule V appear on page 81.

78

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (Note 1) (Continued)

_______________________________________________________________________________
________________________________________

Other Changes - Balance at
Balance at Additions
Add (Deduct) December 31
Classification January 1 at Cost
Retirements (Note 2) (Note 3)
_______________________________________________________________________________
________________________________________

(In Thousands)
Year 1992

Gas utility and other plant
Plant in service . . . . . . . . . . $3,544,531 $ 480,320
$28,489 $ 4,682 $4,001,044
Construction work in progress. . . . . . 191,603 (140,251)
- - 89 51,441
Plant held for future use . . . . . . . 61,932 98
32 (4,744) 57,254
Other property and plant adjustments . . . 47,597 1
(90) (43) 47,645
__________ _________
_______ _________ __________
Total gas utility and other plant . . $3,845,663 $ 340,168
$28,431 $ (16) $4,157,384
========== =========
======= ========= ==========

Exploration and production properties
Plant in service
Production plant
Operated acreage. . . . . . . . . $ 342,641 $ 869
$10,993 $ 9,812 $ 342,329
Other . . . . . . . . . . . . 2,143,137 75,326
57,254 195,788 2,356,997
Non-production plant . . . . . . . . 30,507 3,622
856 (3,863) 29,410
Construction work in progress. . . . . . 16,801 (12,516)
- - - 4,285
Plant held for future use
Unoperated acreage. . . . . . . . . 364,731 31,865
3,599 (201,631) 191,366
Other . . . . . . . . . . . . . 5,685 (93)
136 (125) 5,331
__________ _________
_______ _________ __________
Total exploration and
production properties . . . . . $2,903,502 $ 99,073
$72,838 $ (19) $2,929,718
========== =========
======= ========= ==========
_______________________________________________________________________________
________________________________________
Notes to Schedule V appear on page 81.

79

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (Note 1) (Continued)

_______________________________________________________________________________
________________________________________

Other Changes - Balance at
Balance at Additions
Add (Deduct) December 31
Classification January 1 at Cost
Retirements (Note 2) (Note 3)
_______________________________________________________________________________
________________________________________

(In Thousands)
Year 1991

Gas utility and other plant
Plant in service . . . . . . . . . . $3,327,564 $ 236,208
$26,600 $ 7,359 $3,544,531
Construction work in progress. . . . . . 60,344 131,237
- - 22 191,603
Plant held for future use . . . . . . . 58,524 3,571
13 (150) 61,932
Other property and plant adjustments . . . 88,532 1,560
43,339 844 47,597
__________ _________
_______ _________ __________
Total gas utility and other plant . . $3,534,964 $ 372,576
$69,952 $ 8,075 $3,845,663
========== =========
======= ========= ==========

Exploration and production properties
Plant in service
Production plant
Operated acreage. . . . . . . . . $ 363,575 $ 216
$ 3,096 $ (18,054) $ 342,641
Other . . . . . . . . . . . . 2,134,746 76,305
95,145 27,231 2,143,137
Non-production plant . . . . . . . . 33,829 1,812
422 (4,712) 30,507
Construction work in progress. . . . . . 27,413 (10,612)
- - - 16,801
Plant held for future use
Unoperated acreage. . . . . . . . . 325,756 43,521
251 (4,295) 364,731
Other . . . . . . . . . . . . . 13,244 (47)
160 (7,352) 5,685
__________ _________
_______ _________ __________
Total exploration and
production properties . . . . . $2,898,563 $ 111,195
$99,074 $ (7,182) $2,903,502
========== =========
======= ========= ==========
_______________________________________________________________________________
________________________________________
Notes to Schedule V appear on page 81.

80

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (Note 1) (Concluded)
Notes:

(1) In view of the variety of properties and the large number of depreciation
rates applied by subsidiary companies, it is considered impractical to set
forth the rates used in computing provisions. However, the total provisions
for depreciation of property, plant and equipment for the years ended December
31, 1991 through 1993, including amounts charged to accounts other than
depreciation and amortization expense, were equivalent to approximately 4.8%,
4.3% and 4.2%, respectively, of the average capitalized investment subject to
depreciation and amortization in those periods.

(2) Includes transfers between utility and
exploration and production operations and: 1993 1992 1991
(a) The change in the quantity of gas stored
underground classified as gas plant in
accordance with provisions of the
systems of accounts prescribed by
regulatory authorities . . . . . $3,294 $(35) $ -

(b) Subsequent adjustments to a gas plant
acquisition adjustment arising from
Consolidated's purchase of
Virginia Natural Gas, Inc. in 1990 . - - 893
______ ____ ______

Total utility and exploration and
production operations . . . . $3,294 $(35) $ 893
====== ==== ======

(3) Plant in service for the utility operations includes gas stored
underground in the amounts of $108,180,000, $120,270,000 and $123,564,000 at
December 31, 1991 through 1993, respectively, of which $10,355,000 at the end
of 1991 and $10,342,000 at the end of 1992 and 1993 represents base gas
required under joint operating agreements.

81

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT

_______________________________________________________________________________
________________________________________
Additions
Charged to
Other
Costs and
Changes -
Balance at Expenses
Add (Deduct) Balance at
Description January 1 (Note 1)
Retirements (Note 2) December 31
_______________________________________________________________________________
________________________________________

(In Thousands)
Year 1993

Gas utility and other plant
Accumulated depreciation of gas plant . . . $1,508,116 $ 116,822
$31,117 $ 5,187 $1,599,008
Accumulated amortization and depletion of
producing natural gas land and land rights. 2,485 32
1 - 2,516
Accumulated depreciation and amortization of
other property and plant adjustments. . . 4,657 1,421
(4) - 6,082
__________ _________
_______ _________ __________
Total accumulated depreciation and
amortization applicable to gas utility
and other plant . . . . . . . . $1,515,258 $ 118,275
$31,114 $ 5,187 $1,607,606
========== =========
======= ========= ==========

Exploration and production properties
Accumulated amortization and depletion of
producing natural gas land and land rights. $ 192,745 $ 19,119
$ 4,847 $ - $ 207,017
Accumulated amortization of other property
acquisition, exploration and development costs 1,337,256 139,405
46,400 (3,134) 1,427,127
Accumulated amortization of unproved properties
and estimated future costs . . . . . . 165,427 18,386
30 3,106 186,889
Accumulated depreciation and amortization of
non-production plant . . . . . . . . 1,516 (172)
221 (2) 1,121
__________ _________
_______ _________ __________
Total accumulated depreciation and
amortization applicable to exploration
and production properties . . . . . $1,696,944 $ 176,738
$51,498 $ (30) $1,822,154
========== =========
======= ========= ==========
_______________________________________________________________________________
________________________________________
Notes to Schedule VI appear on page 85.

82

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT (Continued)

_______________________________________________________________________________
________________________________________
Additions
Charged to
Other
Costs and
Changes -
Balance at Expenses
Add (Deduct) Balance at
Description January 1 (Note 1)
Retirements (Note 2) December 31
_______________________________________________________________________________
________________________________________

(In Thousands)
Year 1992

Gas utility and other plant
Accumulated depreciation of gas plant . . . $1,424,723 $ 105,659
$27,701 $ 5,435 $1,508,116
Accumulated amortization and depletion of
producing natural gas land and land rights. 2,454 58
27 - 2,485
Accumulated depreciation and amortization of
other property and plant adjustments. . . 2,861 1,428
(108) 260 4,657
__________ _________
_______ _________ __________
Total accumulated depreciation and
amortization applicable to gas utility
and other plant . . . . . . . . $1,430,038 $ 107,145
$27,620 $ 5,695 $1,515,258
========== =========
======= ========= ==========

Exploration and production properties
Accumulated amortization and depletion of
producing natural gas land and land rights. $ 178,681 $ 19,122
$ 5,047 $ (11) $ 192,745
Accumulated amortization of other property
acquisition, exploration and development costs 1,198,316 137,408
51,743 53,275 1,337,256
Accumulated amortization of unproved properties
and estimated future costs . . . . . . 202,355 24,157
8,002 (53,083) 165,427
Accumulated depreciation and amortization of
non-production plant . . . . . . . . 1,386 143
15 2 1,516
__________ _________
_______ _________ __________
Total accumulated depreciation and
amortization applicable to exploration
and production properties . . . . . $1,580,738 $ 180,830
$64,807 $ 183 $1,696,944
========== =========
======= ========= ==========
_______________________________________________________________________________
________________________________________
Notes to Schedule VI appear on page 85.

83

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT (Continued)

_______________________________________________________________________________
________________________________________
Additions
Charged to
Other
Costs and
Changes -
Balance at Expenses
Add (Deduct) Balance at
Description January 1 (Note 1)
Retirements (Note 2) December 31
_______________________________________________________________________________
________________________________________

(In Thousands)
Year 1991

Gas utility and other plant
Accumulated depreciation of gas plant . . . $1,344,352 $ 97,332
$24,848 $ 7,887 $1,424,723
Accumulated amortization and depletion of
producing natural gas land and land rights. 2,411 54
9 (2) 2,454
Accumulated depreciation and amortization of
other property and plant adjustments. . . 2,119 1,102
339 (21) 2,861
__________ _________
_______ _________ __________
Total accumulated depreciation and
amortization applicable to gas utility
and other plant . . . . . . . . $1,348,882 $ 98,488
$25,196 $ 7,864 $1,430,038
========== =========
======= ========= ==========

Exploration and production properties
Accumulated amortization and depletion of
producing natural gas land and land rights. $ 156,826 $ 24,563
$ 2,706 $ (2) $ 178,681
Accumulated amortization of other property
acquisition, exploration and development costs 1,128,358 143,095
73,586 449 1,198,316
Accumulated amortization of unproved properties
and estimated future costs . . . . . . 183,876 18,532
(183) (236) 202,355
Accumulated depreciation and amortization of
non-production plant . . . . . . . . 2,829 141
- - (1,584) 1,386
__________ _________
_______ _________ __________
Total accumulated depreciation and
amortization applicable to exploration
and production properties . . . . . $1,471,889 $ 186,331
$76,109 $ (1,373) $1,580,738
========== =========
======= ========= ==========
_______________________________________________________________________________
________________________________________
Notes to Schedule VI appear on page 85.

84

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT (Concluded)
Notes:

(1) Includes depreciation and amortization charged to other income and expense
accounts for the years 1991 through 1993 amounting to $107,000, $135,000 and
$365,000, respectively.

(2) Includes transfers between utility and
exploration and production operations.
Also includes charges to miscellaneous
clearing and appointment accounts: 1993 1992 1991
Utility operations . . . . . . . . $4,970 $5,666 $6,329
Exploration and production operations. . 187 212 162
______ ______ ______

Total utility and exploration and
production operations . . . . . . $5,157 $5,878 $6,491
====== ====== ======

85

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
SCHEDULE IX - SHORT-TERM BORROWINGS

_______________________________________________________________________________
________________________________________
Weighted Maximum Amount
Average Amount Weighted Average
Category of Average Outstanding
Outstanding Interest Rate
Aggregate Short- Balance at Interest During the Year
During the Year During the Year
Term Borrowings December 31 Rate (Note 2)
(Note 3) (Note 4)
_______________________________________________________________________________
________________________________________
(Thousands of
Dollars)

Year 1993
Commercial paper
(Note 1) . . $455,000 3.35% $614,400
$351,623 3.28%

Year 1992
Commercial paper. . $460,000 3.41% $500,337
$383,383 3.83%

Year 1991
Commercial paper. . $422,000 4.86% $449,500
$306,548 6.08%

_______________________________________________________________________________
________________________________________

Notes:
(1) The Company's commercial paper notes are issued for gas storage
inventories and other working capital requirements
at a discount which will not be in excess of the discount rate per annum
prevailing at the date of issuance for
commercial paper of comparable quality and like maturities sold to
commercial paper dealers. The notes will
mature not more than 270 days after the date of issue.
(2) Represents the maximum amount outstanding during any month of the year.
(3) Represents the average amount outstanding on a daily basis during the
year.
(4) Represents the weighted average interest rate on a daily basis during the
year.

86

ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Concl.)
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION

_______________________________________________________________________________
Charged to Costs and Expenses
_______________________________________________________________________________
Year Year Year
Item 1993 1992 1991
_______________________________________________________________________________
(Thousands of Dollars)
Maintenance and repairs:
Charged to income account as maintenance $ 87,207 $ 79,128 $ 72,865
Charged to operation expense . . . . 656 826 962
________ ________ ________
$ 87,863 $ 79,954 $ 73,827
======== ======== ========

Depreciation and amortization of
intangible assets, preoperating costs
and similar deferrals . . . . . . (Note) (Note) (Note)

Taxes, other than payroll and income taxes,
charged to income account as other taxes:
Real and personal property taxes . . $ 55,933 $ 52,563 $ 48,066
Excise taxes on gross receipts. . . 75,803 70,743 69,459
Other . . . . . . . . . . . 26,795 24,191 21,691
________ ________ ________
$158,531 $147,497 $139,216
======== ======== ========

Royalties . . . . . . . . . . . $ 55,523 $ 54,400 $ 55,617
Advertising costs . . . . . . . . (Note) (Note) (Note)
_______________________________________________________________________________
Note: Omitted inasmuch as amount is not in excess of one percent of total
sales and revenues as reported in the Consolidated Statement of Income.

87

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 18 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
1993, the year for which this Form 10-K is being filed.

DOCUMENTS FILED AS A PART OF THIS REPORT

Financial Statements
Financial Statement Schedules

All of the financial statements and financial statement schedules filed as a
part of this Report are included in ITEM 8 and reference is made to the index
on page 47.

88

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 con-
stituting part of the Registration Statements on Form S-3 (Nos. 33-1040, 33-
49469 and 33-52585) and Form S-8 (Nos. 2-77204, 2-97948, 33-40478 and 33-44892)
of Consolidated Natural Gas Company of our report dated February 16, 1994,
appearing on page 48 of this Form 10-K. We also consent to the references to
us under the heading "Experts" in such Prospectuses.

PRICE WATERHOUSE

Price Waterhouse

600 Grant Street
Pittsburgh, Pennsylvania 15219-9954
March 28, 1994

EXHIBITS
_______________________________________________________________________________
SEC
Exhibit
Number Description of Exhibit
_______________________________________________________________________________

(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

89

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

EXHIBITS (Continued)
_______________________________________________________________________________
SEC
Exhibit
Number Description of Exhibit
_______________________________________________________________________________

(10) Material Contracts:
(Exhibits (10A) through (10G) listed below are incorporated by
reference to the Exhibit with the same designation filed with
Consolidated Natural Gas Company's Form 10-K for the year ended
December 31, 1987, File No. 1-3196; Exhibits (10H) and (10I)
listed below are incorporated by reference to the Exhibit with the
same designation filed with Consolidated Natural Gas Company's Form
10-K for the year ended December 31, 1989, File No. 1-3196; Exhibit
(10J) listed below is incorporated by reference to the Exhibit with
the same designation filed with Consolidated Natural Gas Company's
Form 10-K for the year ended December 31, 1991, File No. 1-3196;
Exhibit (10K) listed below is incorporated by reference to the
Exhibit with the same designation filed with Consolidated Natural
Gas Company's Form 10-K for the year ended December 31, 1992, File
No. 1-3196)

(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

(10E) Form of agreement between Consolidated Natural Gas Company
and nonemployee 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

(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

(10K) Unfunded Supplemental Benefit Plan for Employees of
Consolidated Natural Gas Company and Its Participating
Subsidiaries Who Are Not Represented by a Recognized Union

90

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

EXHIBITS (Concluded)
_______________________________________________________________________________
SEC
Exhibit
Number Description of Exhibit
_______________________________________________________________________________

(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, 1991 through 1993, 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 1989-1993,
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 15, 1994, 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, 1993, are filed herewith

(23B) Consent letter of John T. Boyd Company, Mining and
Geological Engineers, authorizing the use of coal reserve
estimates in Consolidated Natural Gas Company's Form 10-K
for the year ended December 31, 1993, is filed herewith

(23C) Consent of Price Waterhouse - included as part of this ITEM 14
_______________________________________________________________________________

91

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 28, 1994 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 28, 1994.

GEORGE A. DAVIDSON, JR. THEODORE LEVITT
________________________________ ________________________________
(George A. Davidson, Jr.) (Theodore Levitt)
Chairman of the Board Director
and Chief Executive Officer,
and Director
STEVEN A. MINTER
________________________________
L. D. JOHNSON (Steven A. Minter)
________________________________ Director
(L. D. Johnson)
Executive Vice President
and Chief Financial Officer, WALTER R. PEIRSON
and Director ________________________________
(Walter R. Peirson)
Director
S. R. MCGREEVY
________________________________
(S. R. McGreevy) RICHARD P. SIMMONS
Vice President, Accounting ________________________________
and Financial Control (Richard P. Simmons)
Director

J. W. CONNOLLY
________________________________ A. A. SOMMER, JR.
(J. W. Connolly) ________________________________
Director (A. A. Sommer, Jr.)
Director

PAUL E. LEGO
________________________________ LOIS WYSE
(Paul E. Lego) ________________________________
Director (Lois Wyse)
Director

92

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, 1993 (Page 20)

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 sale or transport connections with wholesale customers and gas
purchase or transport connections with other pipelines. Also shown on the map
are the general location of certain compressor facilities and the general
location of underground storage fields.

Map of Exploration and Production Areas at December 31, 1993 (Page 21)

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.

EXHIBIT INDEX

_______________________________________________________________________________
SEC
Exhibit
Number Description of Exhibit
_______________________________________________________________________________

(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

(10) Material Contracts:
(Exhibits (10A) through (10G) listed below are incorporated by reference
to the Exhibit with the same designation filed with Consolidated Natural
Gas Company's Form 10-K for the year ended December 31, 1987, File No.
1-3196; Exhibits (10H) and (10I) listed below are incorporated by
reference to the Exhibit with the same designation filed with
Consolidated Natural Gas Company's Form 10-K for the year ended
December 31, 1989, File No. 1-3196; Exhibit (10J) listed below is
incorporated by reference to the Exhibit with the same designation filed
with Consolidated Natural Gas Company's Form 10-K for the year ended
December 31, 1991, File No. 1-3196; Exhibit (10K) listed below is
incorporated by reference to the Exhibit with the same designation filed
with Consolidated Natural Gas Company's Form 10-K for the year ended
December 31, 1992, File No. 1-3196)

(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

_______________________________________________________________________________
SEC
Exhibit
Number Description of Exhibit
_______________________________________________________________________________

(10) Material Contracts (Continued):
(10D) System Supplemental Retirement Plan for Certain Management
Employees of Consolidated Natural Gas Company and Its
Participating Subsidiaries

(10E) Form of agreement between Consolidated Natural Gas Company and
nonemployee 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

(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

(10K) Unfunded Supplemental Benefit Plan for Employees of Consolidated
Natural Gas Company and Its Participating Subsidiaries Who Are
Not Represented by a Recognized Union

(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, 1991
through 1993, 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 1989-1993, 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 15, 1994, 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, 1993, are filed herewith

(23B) Consent letter of John T. Boyd Company, Mining and Geological
Engineers, authorizing the use of coal reserve estimates in
Consolidated Natural Gas Company's Form 10-K for the year ended
December 31, 1993, is filed herewith

(23C) Consent of Price Waterhouse - included as part of ITEM 14
_______________________________________________________________________________