CONSOLIDATED NATURAL GAS CO, DEF 14A, 1998-03-03

CONSOLIDATED NATURAL GAS CO
DEF 14A, 1998-03-03
NATURAL GAS TRANSMISISON & DISTRIBUTION

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<PAGE> 1
SCHEDULE 14A INFORMATION

PROXY STATEMENT PURSUANT TO SECTION 14(a) OF THE SECURITIES
EXCHANGE ACT OF 1934 (AMENDMENT NO. )

Filed by the Registrant / /

Filed by a Party other than the Registrant / /

Check the appropriate box:

<TABLE>
<S> <C>
/ / Preliminary Proxy Statement / / Confidential, for Use of the Commission
Only (as permitted by Rule 14a-6(e)(2))
/x/ Definitive Proxy Statement
/ / Definitive Additional Materials
/ / Soliciting Material Pursuant to Rule 14a-11(c) or Rule 14a-12
</TABLE>

Consolidated Natural Gas Company
- - --------------------------------------------------------------------------------
(Name of Registrant as Specified In Its Charter)

- - --------------------------------------------------------------------------------
(Name of Person(s) Filing Proxy Statement, if other than the Registrant)

Payment of Filing Fee (Check the appropriate box):

/ / $125 per Exchange Act Rules 0-11(c)(1)(ii), 14a-6(i)(1), or 14a-6(i)(2) or
Item 22(a)(2) of Schedule 14A.

/ / $500 per each party to the controversy pursuant to Exchange Act Rule
14a-6(i)(3).

/ / Fee computed on table below per Exchange Act Rules 14a-6(i)(4) and 0-11.

(1) Title of each class of securities to which transaction applies:

(2) Aggregate number of securities to which transaction applies:

(3) Per unit price or other underlying value of transaction computed
pursuant to Exchange Act Rule 0-11 (Set forth the amount on which the
filing fee is calculated and state how it was determined):

(4) Proposed maximum aggregate value of transaction:

(5) Total fee paid:

/ / Fee paid previously with preliminary materials.

/ / Check box if any part of the fee is offset as provided by Exchange Act Rule
0-11(a)(2) and identify the filing for which the offsetting fee was paid
previously. Identify the previous filing by registration statement number,
or the Form or Schedule and the date of its filing.

(1) Amount Previously Paid:

(2) Form, Schedule or Registration Statement No.:

(3) Filing Party:

(4) Date Filed:

* No fee required
<PAGE> 2

CONSOLIDATED
CNG NATURAL GAS
COMPANY

CONSOLIDATED 1998 Notice of
CNG NATURAL GAS Annual Meeting and
COMPANY Proxy Statement

CONSOLIDATED
CNG NATURAL GAS
COMPANY

CONSOLIDATED
CNG NATURAL GAS
COMPANY
<PAGE> 3

CONSOLIDATED NATURAL GAS COMPANY

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Chairman's Letter........................................... 1
Notice of Meeting........................................... 2
Proxy Statement............................................. 3
Voting Securities and Principal Holders..................... 3
Election of Directors....................................... 4
Board Committees............................................ 8
Security Ownership.......................................... 9
Compensation Table.......................................... 10
Option Grants............................................... 10
Option Exercise Table....................................... 11
Human Resources Committee Report............................ 11
Shareholder Performance Graph............................... 14
Directors' Compensation..................................... 15
Benefit Plans............................................... 16
Independent Accountants..................................... 17
Stockholder's Proposal...................................... 18
Other Matters............................................... 20
Appendix I--1997 Financial Statements and Notes to
Statements................................................ Enclosed
</TABLE>
<PAGE> 4

CONSOLIDATED NATURAL GAS COMPANY

February 23, 1998

Dear Stockholder:

You are cordially invited to attend the 1998 Annual Meeting of Stockholders to
be held on Tuesday, April 14, 1998, at 10:00 a.m. Eastern Time at the Harborside
Hyatt Conference Center and Hotel, 101 Harborside Drive, Boston, Massachusetts
02128.

The business items to be acted on during the Meeting are listed in the Notice of
Meeting and are described more fully in the Proxy Statement. The Board of
Directors has given careful consideration to these proposals and believes that
Proposals 1 and 2 are in the best interests of the Company and its stockholders
and that Proposal 3 is not in the best interests of the Company or its
stockholders. The Board recommends that you vote FOR Proposals 1 and 2 and
AGAINST Proposal 3.

It is important that you be represented at the Annual Meeting in person or by
proxy. Whether or not you plan to attend, we urge you to mark, sign, date and
return the enclosed proxy card promptly in the postage-paid envelope provided or
call the toll-free telephone number on the proxy card to give your voting
instructions. If you plan to attend, please check the appropriate box on the
proxy card or advise while voting by telephone.

Thank you for your cooperation.

Sincerely,

/s/ GEORGE A. DAVIDSON, JR.
-----------------------------
George A. Davidson, Jr.
Chairman of the Board and
Chief Executive Officer

1
<PAGE> 5

CONSOLIDATED NATURAL GAS COMPANY
NOTICE OF ANNUAL MEETING OF STOCKHOLDERS

The Annual Meeting of Consolidated Natural Gas Company will be held on Tuesday,
April 14, 1998, at 10:00 a.m. Eastern Time at the Harborside Hyatt Conference
Center and Hotel, 101 Harborside Drive, Boston, Massachusetts 02128.
Stockholders of record at the close of business on February 23, 1998, will be
entitled to vote at the Meeting and any adjournment thereof.

The agenda for the Meeting includes:

1. Election of three Directors.
2. Ratification of the appointment of Price Waterhouse LLP as independent
accountants.
3. Action on a stockholder-proposed resolution regarding the shareholder
rights plan.
4. Transaction of any other business which may be properly brought before
the Meeting.

In the event you cannot be present in person, please sign and promptly return
the enclosed proxy card in the accompanying postage-paid envelope, or call the
toll-free telephone number on the proxy card to give your voting instructions,
so that your shares will be represented at the Meeting. Prompt return of proxies
will save the Company the expense of further requests for proxies to ensure a
quorum.

By order of the Board of Directors,

/s/ LAURA J. MCKEOWN
--------------------
Laura J. McKeown
Secretary

Pittsburgh, Pennsylvania
February 23, 1998

ATTENTION: STOCKHOLDERS PARTICIPATING IN THE DIVIDEND REINVESTMENT PLAN
The accompanying proxy card reflects the total shares of Common Stock registered
in your name directly, as well as any full shares credited to your Dividend
Reinvestment Plan account.

2
<PAGE> 6

CONSOLIDATED NATURAL GAS COMPANY
PROXY STATEMENT

This statement and proxy card, mailed to stockholders commencing March 5, 1998,
are furnished in connection with the solicitation by the Board of Directors of
Consolidated Natural Gas Company of proxies to be voted at the Annual Meeting of
Stockholders, and any adjournment thereof, for the purposes stated in the Notice
of the Annual Meeting. This year, stockholders can give proxies by mailing their
signed proxy cards or by calling a toll-free telephone number. The telephone
voting procedures are designed to authenticate stockholders' identities, to
allow stockholders to give their voting instructions, and to confirm that
stockholders' instructions have been recorded properly. The Company has been
advised by counsel that the procedures that have been put in place are
consistent with the requirements of applicable law. Specific instructions for
stockholders who wish to use the telephone voting procedure are set forth on the
enclosed proxy card. Any stockholder who cannot attend the Annual Meeting is
requested to sign and return the accompanying proxy card or call the toll-free
telephone number on the proxy card promptly.
The proxy reflects the number of shares registered in a stockholder's name
directly and, for participants in the Company's Dividend Reinvestment Plan,
includes full shares credited to a participant's Dividend Reinvestment Plan
account. Proxies so given will be voted on all matters brought before the
Meeting and, as to the matters with respect to which a choice is specified, will
be voted as directed. The cost of solicitation will be paid by the Company. In
addition to the use of the mails, proxies may be solicited personally, or by
telephone, telecopy or other electronic means, by employees of the Company and
its subsidiaries with no special compensation to these employees. Georgeson &
Company Inc., Wall Street Plaza, New York, New York 10005, has been retained to
assist in the solicitation of proxies at an estimated cost of $8,000. The
Company will reimburse brokerage houses and other custodians, nominees and
fiduciaries for expenses incurred in sending proxy material to their principals.
Any proxy given pursuant to this solicitation may be revoked at any time
prior to exercise by written notice to the Corporate Secretary, by filing a
later dated executed proxy, or by attending and voting at the Annual Meeting.
The address of the principal executive offices of the Company is Consolidated
Natural Gas Company, CNG Tower, 625 Liberty Avenue, Pittsburgh, Pennsylvania
15222-3199.

Voting Securities and Principal Holders
Holders of Common Stock, $2.75 par value, of record on February 23, 1998, have
one vote for each share held. On January 31, 1998, 91,088,370 shares of Common
Stock were outstanding. A majority of the outstanding shares will constitute a
quorum at the Meeting. Abstentions and broker non-votes are counted for purposes
of determining the presence or absence of a quorum for the transaction of
business. Abstentions are counted in tabulations of the votes cast on proposals
presented to stockholders. Broker non-votes are not counted for purposes of
determining whether a proposal has been approved.
The following table indicates the beneficial ownership, as of December 31,
1997, of the Company's Common Stock with respect to the only persons known to
the Company to be the beneficial owner of more than 5% of such Common Stock. On
December 31, 1997, 95,622,622 shares of Common Stock were outstanding.

<TABLE>
<CAPTION>
- - ------------------------------------------------------------------------------------------------------------
Name and Address of Amount and Nature Percent of Outstanding
Beneficial Owner of Beneficial Ownership Common Stock
- - ------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Trustees, Alternate Thrift Trust of Employees Thrift Plans(1)
CNG Tower, 625 Liberty Avenue, Pittsburgh, PA 15222-3199 5,084,893(2) 5.3%
Trustees, Long-Term Thrift Trust of Employees Thrift Plan(1)
CNG Tower, 625 Liberty Avenue, Pittsburgh, PA 15222-3199 3,642,290(3) 3.8%
</TABLE>

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

(1) The Alternate and Long-Term Thrift Trusts beneficially hold shares for
employees under the various Company sponsored defined contribution plans.

(2) Such shares are beneficially owned in varying amounts by 3,731 employees, no
one of whom beneficially owned in excess of 9,400 shares in the Plans, or
1/100ths of 1% of the shares outstanding. Such shares are voted pursuant to
confidential instructions of participating employees and, in the absence of
instructions, such shares are not voted. A Registration Statement relating
to various investment options available to participants in the Plans has
been made effective under the Securities Act of 1933 and is on file with the
Securities and Exchange Commission (SEC).

(3) Such shares are beneficially owned in varying amounts by 2,486 employees, no
one of whom beneficially owned in excess of 14,300 shares in the Plan, or
2/100ths of 1% of the shares outstanding. Such shares are voted pursuant to
confidential instructions of participating employees and, in the absence of
instructions, Trustees, Long-Term Thrift Trust of Employees Thrift Plan
shall vote unvoted shares in the same proportion as shares voted pursuant to
confidential instructions. A Registration Statement relating to various
investment options available to participants in the Plan has been made
effective under the Securities Act of 1933 and is on file with the SEC.
- - --------------------------------------------------------------------------------

3
<PAGE> 7

The Board of Directors does not know of any other persons or groups who
beneficially own 5% or more of the outstanding shares of Common Stock.

ANNUAL REPORT
Commencing on or about March 5, 1998, the Company's Summary Annual Report for
the year ended December 31, 1997, was mailed together with this Notice of Annual
Meeting and Proxy Statement. Financial statements for the year ended December
31, 1997, are included as part of Appendix I to this Notice of Annual Meeting
and Proxy Statement and were mailed to stockholders of record on February 23,
1998. The Company will provide a copy of the Summary Annual Report to anyone
else upon request in writing to the Corporate Secretary, Consolidated Natural
Gas Company, CNG Tower, 625 Liberty Avenue, Pittsburgh, Pennsylvania 15222-3199.

PROPOSAL 1
ELECTION OF DIRECTORS

The Board of Directors consists of nine members divided into three classes. Each
class has a three-year term, and only one class is elected each year. There are
no family relationships among any of the nominees, continuing Directors and
Executive Officers of the Company nor any arrangement or understanding between
any Director or Executive Officer or any other person pursuant to which any of
the nominees has been nominated. During 1997, each of the members of the Board
of Directors attended more than 75% of the aggregate of the Board meetings and
meetings held by all committees of the Board on which the Director served during
the periods that the Director served, except for Mr. Connolly.
On recommendation of the Governance Committee of the Board of Directors,
three incumbent Class II Directors have been designated nominees for reelection;
each has consented to be a nominee and to serve if elected. The remaining
Directors will continue to serve in accordance with their previous elections.
The names and other information concerning the three persons nominated for a
term of three years and the five continuing Board members are set forth by Class
on pages 5 through 7 of this Proxy Statement. The personal information has been
furnished to the Company by the nominees and other Directors. Unless you specify
otherwise on your signed proxy card, your shares will be voted FOR the election
of the three persons named to three-year terms as Directors. In the event of an
unexpected vacancy on the slate of nominees, your shares will be voted for the
election of a substitute nominee if one shall be designated by the Board. If any
nominee for election as Director is unable to serve, which the Board of
Directors does not anticipate, the persons named in the proxy may vote for
another person in accordance with their judgment.

VOTE NEEDED FOR ELECTION OF DIRECTORS
Directors are elected by a plurality of the votes of the shares of Common Stock
present in person or represented by proxy and entitled to vote at the Annual
Meeting. Any shares not voted (whether by abstention, broker non-vote or votes
withheld) are not counted as votes cast for such individuals and will be
excluded from the vote.

BOARD RECOMMENDATION
The Board recommends that stockholders vote FOR Proposal 1, and the accompanying
proxy will be so voted, unless a contrary specification is made.

4
<PAGE> 8

DIRECTORS NOMINATED FOR ELECTION TO THE BOARD WITH A TERM EXPIRING APRIL 2001

(Photo
omitted) J. W. CONNOLLY Chair: Financial Committee
Age 64 Member: Executive Committee
Director since 1984 Human Resources Committee
International Committee

Mr. Connolly served as Senior Vice President and Director of H. J. Heinz
Company, Pittsburgh, Pennsylvania, a processed food products
manufacturer, from 1985 to his retirement in December 1993. He
served as President and Chief Executive Officer of Heinz U.S.A., a
division of the H. J. Heinz Company, from 1980 to 1985, and served
as Executive Vice President of that company from 1979 to 1980. He
was President and Chief Executive Officer of The Hubinger Company, a Heinz
Company subsidiary, from 1976 to 1979, Treasurer of H. J. Heinz Company from
1973 to 1976, and a Vice President of Ore-Ida Foods, Inc., a Heinz Company
subsidiary, from 1967 to 1973. An attorney by profession, Mr. Connolly joined
the Law Department of the H. J. Heinz Company in 1961. He is a Director of
Mellon Bank Corporation, Mellon Bank, N.A., First Vice Chairperson for UPMC
Health System Board of Directors, and Second Vice Chairperson for the Joint UPMC
Presbyterian/UPMC Shadyside Boards of Directors. He is also Chairman, Board of
Trustees of the University of Pittsburgh.

(Photo
omitted) GEORGE A. DAVIDSON, JR. Chair: Executive Committee
Age 59 Member: Financial Committee
Director since 1985

Mr. Davidson has served as Chairman of the Board and Chief Executive Officer of
the Company since May 1987, and has been employed by Consolidated
since 1966. He served as Vice Chairman and Chief Operating Officer
of the Company from January 1987 to May 1987, and Vice Chairman
from October 1985 to January 1987. He served as President of CNG
Transmission Corporation((1)) from 1984 through 1985. He had been
Vice President, System Gas Operations, for Consolidated Natural
Gas Service Company, Inc.,(1) from 1981 to 1984, and was Assistant Vice
President, Rates and Certificates, of that company from 1975 to 1981. Mr.
Davidson held various other positions in the Rates and Certificates Department
from 1966 to 1975. Mr. Davidson serves on the National Petroleum Council and the
Allegheny Conference on Community Development. He is a Director of the American
Gas Association, PNC Bank Corp. and B. F. Goodrich Company. He is also a Trustee
of the University of Pittsburgh.

(Photo
omitted)
RICHARD P. SIMMONS Chair: Audit Committee
Age 66 Member: Compliance Committee
Director since 1990 Executive Committee
Governance Committee

Mr. Simmons has served as Chairman, President and Chief Executive Officer of
Allegheny Teledyne Incorporated, Pittsburgh, Pennsylvania, an
international specialty steel manufacturer since February 1997. He
served as Chairman of Allegheny Teledyne Incorporated since August
1996. He served as Chairman and Chairman of the Executive
Committee of Allegheny Ludlum Corporation, a predecessor company,
since 1990. He served as Chairman and Chief Executive Officer of Allegheny
Ludlum from 1980 to 1990 and as a Director of that company since 1980. He was a
Director of Allegheny Ludlum Industries from 1973 to 1980 and a member of the
Executive Office of that company from 1978 to 1980. Mr. Simmons is a Director of
PNC Bank Corp. He is a member of the Massachusetts Institute of Technology
Corporation and Development Committee, and Chairman and a member of the
Executive Committee of the Allegheny Conference on Community Development.

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

(1) Wholly owned subsidiary of the Company.

5
<PAGE> 9

CONTINUING DIRECTORS WITH A TERM EXPIRING MAY 1999

(Photo
omitted) RAYMOND E. GALVIN Member: Audit Committee
Age 66 Compliance Committee
Director since 1998

Mr. Galvin served as President of Chevron U.S.A. Production Company, an oil and
gas exploration, development and production company, Houston,
Texas, from January 1992 until his retirement in February 1997 and
as a Director of Chevron Corporation from 1995 until 1997. He
served as Senior Vice President, exploration, land and production,
for Chevron U.S.A. from 1988 to 1992, and a Vice President of
Chevron Corporation from 1988 to 1997. Upon implementation of the Gulf-Chevron
Corporation merger in 1985 and until 1988, he served as Vice President,
exploration, land and production, for Chevron U.S.A. Inc. in its Southern and
Eastern Regions. Prior thereto, he served in various engineering and management
positions with Gulf Oil Corporation from 1953 to 1985. He currently serves on
the Board of Trustees of the Houston Museum of Natural Science and on the
Houston Advisory Board of the Nature Conservancy of Texas. He is a fellow,
External Advisory Council, College of Engineering, Texas A&M University.

(Photo
omitted) PAUL E. LEGO Chair: International Committee
Age 67 Member: Executive Committee
Director since 1991 Financial Committee
Human Resources Committee

Mr. Lego served as Chairman and Chief Executive Officer of Westinghouse Electric
Corporation, Pittsburgh, Pennsylvania, an electronic products and
services, environmental systems and broadcasting company from 1990
to his retirement in January 1993. He served that company as
President and Chief Operating Officer from 1988 to 1990 and as a
Director from 1988 to 1993. He had been Senior Executive Vice
President, Corporate Resources from 1985 to 1988, Executive Vice President,
Westinghouse Industries & International Group from 1983 to 1985 and Executive
Vice President, Westinghouse Industry Products from 1980 to 1983. Prior thereto,
he served in various engineering and management capacities with Westinghouse
since 1956. Mr. Lego is the non-executive Chairman of the Board of Commonwealth
Industries, Inc. and a Director of the Lincoln Electric Company and USX
Corporation. He is a member of the Business Council and a Trustee of the
University of Pittsburgh.

(Photo
omitted) MARGARET A. MCKENNA Chair: Compliance Committee
Age 52 Member: Governance Committee
Director since 1994 Human Resources Committee

Ms. McKenna has served as President of Lesley College, Cambridge, Massachusetts,
since 1985. She served as Vice President, Program Planning,
Radcliffe College from 1982 to 1985 and as Director of its Bunting
Institute from 1981 to 1985. Prior thereto, she had served as
Deputy Under Secretary of the U.S. Department of Education, Deputy
Counsel to the President of the United States, and in posts with
the International Association of Human Rights agencies and U.S. Department of
Justice. Ms. McKenna is a Director of The Stride Rite Corporation.

6
<PAGE> 10

CONTINUING DIRECTORS WITH A TERM EXPIRING MAY 2000

(Photo
omitted) WILLIAM S. BARRACK, JR. Member: Audit Committee
Age 68 Compliance Committee
Director since 1994 Executive Committee
International Committee

Mr. Barrack served as Senior Vice President of Texaco Inc., Harrison, New York,
an integrated international oil company and a producer of natural
gas, from 1983 to his retirement in 1992. He served as a Senior
Director of Caltex Petroleum Corporation from 1982 to 1992,
President of Texaco Oil Trading & Supply Company from 1983 to
1984, and Chairman and Chief Executive Officer of Texaco
Limited-London from 1980 to 1983. Prior thereto, he served in various marketing,
producing and management positions with Texaco Inc. since 1953. Mr. Barrack is a
Director of Standard Commercial Corporation.

(Photo
omitted) RAY J. GROVES Chair: Governance Committee
Age 62 Member: Audit Committee
Director since 1994 Financial Committee
International Committee

Mr. Groves served as Chairman and Chief Executive Officer of Ernst & Young, New
York, New York, a public accounting firm, from 1991 to his
retirement in 1994. He served as Co-Chief Executive Officer of the
firm from 1989 to 1991 and served as Chairman and Chief Executive
Officer of Ernst & Whinney from 1977 to 1989. Mr. Groves was
admitted as a Partner in the firm in 1966, having joined the firm
in 1957. Mr. Groves is the Chairman of Legg Mason Merchant Banking Inc., a
Director of Electronic Data Systems Corp., Lamalie Associates, Inc., Marsh &
McLennan Companies, Inc., and RJR Nabisco, Inc. Mr. Groves serves as a Trustee
of The Business Council for the United Nations, the Public Policy Institute,
Vice Chairman of The Ohio State University Foundation and as a Managing Director
and Treasurer of the Metropolitan Opera Association.

(Photo
omitted) STEVEN A. MINTER Chair: Human Resources Committee
Age 59 Member: Compliance Committee
Director since 1988 Governance Committee

Mr. Minter has been the Executive Director and President of The Cleveland
Foundation, Cleveland, Ohio, since 1984, an organization
supporting health, human services, cultural and educational
programs in the greater Cleveland area. He had been Associate
Director and Program Officer of The Cleveland Foundation from 1975
to 1980 and from 1981 to 1983. He served as Under Secretary of the
U.S. Department of Education, Washington, D.C., from 1980 to 1981.
He was the Commissioner of Public Welfare for the Commonwealth of
Massachusetts from 1970 to 1975. Mr. Minter is a Director of Goodyear Tire &
Rubber Company, Rubbermaid Inc., and KeyCorp. He is also a Trustee of the
College of Wooster and of The Foundation Center.

7
<PAGE> 11

THE BOARD OF DIRECTORS AND CERTAIN COMMITTEES THEREOF

BOARD OF DIRECTORS
The Company is managed under the direction of the Board of Directors, which met
seven times in 1997. To assist it in various areas of responsibility, the Board
has established several standing committees that are briefly described below.

AUDIT COMMITTEE
The Audit Committee is comprised of four non-employee Directors. The Audit
Committee assists the Board in fulfilling its oversight responsibilities by
reviewing the financial information to be provided to shareholders and others,
and by reviewing the audit process and any related internal control findings of
the internal auditors and independent accountants. The Committee also selects
and recommends to the Board the employment of independent accountants and
approves fees charged by independent accountants. The Committee met four times
in 1997.

COMPLIANCE COMMITTEE
The Compliance Committee consists of five non-employee Directors. It reviews and
monitors policies and procedures to prevent, detect and deter violations of the
law and violations of the Company's Business Ethics Policy. It also reviews the
results of the Annual Business Ethics and Compliance Surveys. The Committee met
four times in 1997.

EXECUTIVE COMMITTEE
The Executive Committee consists of four non-employee Directors and the Chairman
of the Board. It has the authority to act in emergency situations and can
exercise all the powers of the Board of Directors. The Committee did not meet in
1997.

FINANCIAL COMMITTEE
The Financial Committee consists of three non-employee Directors and the
Chairman of the Board. Its function is to oversee the short-term and long-term
financial activities and planning of the Company, including dividend actions.
The Committee met six times in 1997.

GOVERNANCE COMMITTEE
The Governance Committee consists of four non-employee Directors. It monitors
corporate governance matters, including the structure, process and procedures of
the Board, and reviews the qualifications of Director candidates on the basis of
recognized achievements and their ability to bring skills and experience to the
deliberations of the Board. It also recommends qualified candidates to the
Board, including the slate of nominees submitted to the stockholders at the
Annual Meeting; reviews the size and composition of the Board; annually reviews
Directors' compensation and benefits; makes recommendations to the Board; and
monitors the Company's CEO succession plans. The Committee met four times in
1997.
Stockholders who wish to propose candidates to the Governance Committee for
election to the Board at the 1999 Annual Meeting should write to the Corporate
Secretary, Consolidated Natural Gas Company, CNG Tower, 625 Liberty Avenue,
Pittsburgh, Pennsylvania 15222-3199, in accordance with the Company's bylaws,
stating in detail the qualifications of such candidates for consideration by the
Committee. Any such recommendation should be accompanied by a written statement
from the candidate of his or her consent to be considered as a candidate and, if
nominated and elected, to serve as a Director.

HUMAN RESOURCES COMMITTEE
The Human Resources Committee is comprised of four non-employee Directors. The
Committee reviews senior executive succession plans, compliance with affirmative
action and work force diversity plans. It approves the salary budgets and
incentive plans for all non-union employees, reviews senior executive salary
changes and incentive awards and establishes the salary and incentives of the
Chairman and Chief Executive Officer. The Committee also has general supervision
over the administration of all non-union employee pension, compensation and
benefit plans of the Company and its subsidiaries; reviews proposals with
respect to the creation of and changes in such plans; and makes recommendations
with respect thereto to the Board of Directors. The Committee met four times in
1997.

INTERNATIONAL COMMITTEE
The International Committee is comprised of four non-employee Directors. Its
function is to review and take action on matters concerning CNG International
Corporation. The Committee advises, consults and assists in the screening of
projects prior to their recommendation to the Board of Directors for investment.
The Committee met six times in 1997.

8
<PAGE> 12

SECURITY OWNERSHIP OF DIRECTORS AND OFFICERS

The following table lists the beneficial ownership, as of December 31, 1997, of
the Company's Common Stock by each current Director, named executive, and all
current Directors and Officers as a group.
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
(a) (b) (a)+(b)
--------------------------- ------------
Number of Number of Director's Percent of
Shares Shares Under Deferred Outstanding
Name of Beneficially Exercisable Compensation Common
Beneficial Owner Owned(1)(2) Options(3) Stock Credits(4) Stock
<S> <C> <C> <C> <C>
- - --------------------------------------------------------------------------------------------------------------------
W. S. Barrack, Jr. 795 5,987 .001
J. W. Connolly 1,000 8,616 .001
G. A. Davidson, Jr. 127,279 101,484 .239
R. J. Groves 1,301 7,902 .001
P. E. Lego 800 5,431 .001
S. R. McGreevy 14,962 14,242 .031
M. A. McKenna 3,767 1,409 .004
S. A. Minter 1,600 4,038 .002
H. P. Riley 36,605 1,939 .040
R. P. Simmons 6,493 5,615 .007
D. M. Westfall 41,664 19,077 .064
S. E. Williams 36,562 34,004 .074
Directors and Officers of the Company as a group (14
persons) 279,416 194,128 38,998 .495
</TABLE>

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

(1) Includes shares owned by spouses and, in the case of employees, shares
beneficially owned under the Long-Term Thrift Trust of the Employees Thrift
Plan and the Employee Stock Ownership Plan. Unless otherwise noted, the
Directors and Officers have sole voting and investment power.

(2) Includes Performance Restricted Stock Awards and Restricted Stock Awards
granted pursuant to the Long Term Strategic Incentive Program.

(3) Includes shares subject to options exercisable on December 31, 1997, and
options which will become exercisable within 60 days thereafter.

(4) Director's compensation deferred in the form of CNG stock credits, as
described under Non-Employee Directors' Compensation on page 14, is not
included in the percentage shown in the last column.
- - --------------------------------------------------------------------------------

9
<PAGE> 13

COMPENSATION OF EXECUTIVE OFFICERS

The following table sets forth the compensation of the named Executive Officers
for the last three completed fiscal years of the Company.

SUMMARY COMPENSATION TABLE
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
Long-Term
Annual Compensation Compensation
------------------------------------- ----------------------
Other Restricted Shares All
Name and Annual Stock Underlying Other
Principal Position Year Salary Bonus Compensation(1) Award(s)(2) Options Compensation(5)
<S> <C> <C> <C> <C> <C> <C> <C>
- - ---------------------------------------------------------------------------------------------------------------------
G. A. Davidson, Jr. 1997 $632,650 $400,000 $ 8,922 0 0 $63,472
(Chairman and Chief 1996 598,750 360,000 10,061 84,000 280,000(3) 56,465
Executive Officer, Director) 1995 568,000 213,600 7,511 0 77,768(4) 42,853
S. R. McGreevy 1997 165,800 70,800 184 0 0 8,497
(Vice President, Accounting 1996 159,520 76,000 1,188 13,500 45,000(3) 8,193
and Financial Control) 1995 154,250 41,100 844 0 19,752(4) 7,966
H. P. Riley 1997 269,335 125,000 54,038 0 0 13,674
(President, CNG 1996 256,250 162,000 57,184 31,400 105,000(3) 13,029
Producing Company) 1995 83,335 46,200 7,594 6,204 7,755(4) 5,416
D. M. Westfall 1997 245,800 150,000 2,640 0 0 18,643
(Sr. Vice President and 1996 217,050 139,000 10,684 31,400 105,000(3) 16,322
Chief Financial Officer) 1995 174,600 67,800 1,717 1,506 13,886(4) 13,519
S. E. Williams 1997 254,570 140,000 3,265 0 0 19,300
(Sr. Vice President and 1996 240,900 153,000 4,457 23,300 78,000(3) 18,286
General Counsel) 1995 227,400 68,300 3,504 0 22,085(4) 17,307
</TABLE>

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

(1) Includes only tax reimbursements for Messrs. Davidson, McGreevy, Westfall
and Williams. No amounts are included in this column for the Executive
Split-Dollar Life Insurance Plan because the executives' contributions to
this plan are greater than or equal to the term life insurance costs that
apply to the underlying life insurance policies. Includes living expenses
and personal travel of $26,730 and related tax reimbursements of $21,385 for
Mr. Riley in 1996, and living expenses and personal travel of $26,080 and
related tax reimbursements of $20,864 for Mr. Riley in 1997.

(2) Restricted Stock Award and Performance Restricted Stock Awards Grants are
based on the individual's level of performance and responsibility.
Restrictions on the Restricted Stock Awards granted in 1995 lapse in 25%
increments on the first through fourth anniversaries of the grant date.
Restrictions on the Restricted Stock Awards granted in 1996 lapse on March
1, 1999, and once vested must be held until March 1, 2001. Restrictions on
the Performance Restricted Stock Awards granted in 1996 lapse on March 1,
1999, subject to the achievement of performance levels. Dividends are paid
on Restricted Stock from the date of grant. Dividends on Performance
Restricted Stock are held by the Company from the date of the grant, subject
to the achievement of performance levels.

At December 31, 1997, the number of Restricted Stock holdings for each of the
named Executive Officers was: Mr. Davidson, 14,000; Mr. McGreevy, 2,200; Mr.
Riley, 8,202; Mr. Westfall, 5,476; and Mr. Williams, 3,800 and the number of
Performance Restricted Stock holdings for each of the named Executive
Officers was: Mr. Davidson, 70,000; Mr. McGreevy, 11,300; Mr. Riley, 26,300;
Mr. Westfall, 26,300; and Mr. Williams, 19,500. The aggregate values of such
holdings at December 31, 1997, at the year-end closing price of $60.50 per
share, for each of the named Executive Officers was: Mr. Davidson,
$5,082,000; Mr. McGreevy, $816,750; Mr. Riley, $2,087,371; Mr. Westfall,
$1,922,448; and Mr. Williams, $1,409,650.

(3) Triannual Non-Qualified Stock Options.

(4) Non-Qualified Stock Options.

(5) Comprising annual employer matching thrift plan contributions and ESOP
allocations.
- - --------------------------------------------------------------------------------

OPTION GRANTS IN LAST FISCAL YEAR

No Triannual Stock Options, Non-Qualified Stock Options or Stock Appreciation
Rights ("SARs") were granted in 1997 to the named Executive Officers.

10
<PAGE> 14

The following table sets forth information with respect to the named Executive
Officers concerning the exercise of options during the last fiscal year of the
Company and unexercised options held as of the end of the fiscal year.

AGGREGATED NON-QUALIFIED STOCK OPTION EXERCISES IN LAST FISCAL YEAR AND DECEMBER
31, 1997, YEAR-END NON-QUALIFIED STOCK OPTION VALUES
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
Number of Shares Value of Unexercised,
Underlying Unexercised In-the-Money Options
Shares Options Held at Year-End at Year-End(2)
Acquired On Value --------------------------- ---------------------------
Name Exercise Realized(1) Exercisable Unexercisable Exercisable Unexercisable
<S> <C> <C> <C> <C> <C> <C>
- - ----------------------------------------------------------------------------------------------------------
G. A. Davidson, Jr. 59,007 $1,051,104 67,813 79,956 $1,119,015 $1,697,470
S. R. McGreevy 6,204 142,471 6,634 18,873 92,145 408,492
H. P. Riley 0 0 1,939 5,816 39,750 119,228
D. M. Westfall 0 0 14,338 12,342 275,718 272,560
S. E. Williams 0 0 24,988 22,193 463,718 474,735
</TABLE>

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

(1) Market value of underlying shares at time of exercise minus the exercise
price.

(2) Market value of underlying shares at year-end market price of $60.50 per
share minus the exercise price.
- - --------------------------------------------------------------------------------

LONG-TERM INCENTIVE PLAN AWARDS IN THE LAST FISCAL YEAR

No awards were granted in 1997 to the named Executive Officers under the
Long-Term Incentive Plan.

EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AGREEMENTS

Messrs. Davidson, McGreevy, Riley, Westfall and Williams entered into agreements
with the Company dated December 12, 1995, that have provisions which become
operative upon a defined change of control of the Company. Such agreements
preserve for three years following a change of control the annual salary levels
and employee benefits as are then in effect for these executives and provide
that, in the event of certain terminations of employment, these executives shall
receive severance payments equal to 2.99 times their respective annual
compensation prior to severance. The agreements also provide for the Company to
reimburse the employee for the payment of certain excise taxes and for a related
tax gross-up payment, if any, payable in connection with compensation paid under
such agreement.

HUMAN RESOURCES COMMITTEE REPORT

SUMMARY

The Company's executive compensation programs are administered by the Human
Resources Committee of the Board of Directors (the "Committee"), which is
comprised of four non-employee Directors. The Committee reviews and approves all
issues pertaining to executive compensation. Total compensation is designed in
relationship to compensation paid by competitor organizations. Base salary and
long-term incentive compensation are targeted to median market levels, and
short-term incentive compensation is goal-based and structured to be comparable
to that paid by competitor organizations. The objective of the Company's three
compensation programs (base salary, short-term incentive and long-term
incentive) is to provide a total compensation package that will enable the
Company to attract, motivate and retain outstanding individuals and align their
success with that of the Company's shareholders.
Competitor organizations are defined annually as part of the compensation
administration process and include fully integrated natural gas companies as
well as broader industry comparatives, e.g., comparably sized general industrial
companies and, where appropriate, specific energy companies.

11
<PAGE> 15

BASE SALARY

The level of base salary paid to executives for 1997 was determined on the basis
of performance and experience. The Company measures or identifies its base
salary structure by a range of market reference points in comparison to base
salaries offered by competitors. Salary levels are targeted to and, in 1997,
correspond with the median range of compensation paid by competitor
organizations. These are not the same companies that comprise the Value Line
Natural Gas Diversified Industry Index shown on the shareholder return
performance presentation. The specific competitive marketplace that the Company
and its subsidiaries use in base salary analysis is determined based on the
nature and level of the positions being analyzed and the labor markets from
which individuals would be recruited. The Committee also considered the
competitiveness of the entire compensation package in its approval of salary
levels paid to senior executives.

SHORT-TERM INCENTIVE COMPENSATION

Short-term incentive compensation plans are used at both CNG Corporate and
Business Segment levels. Short-term incentive opportunity is structured so that
awards are competitive at a level commensurate with the performance level
achieved by the Company with consideration for the executive's performance and
level of responsibility. The short-term incentive plan has threshold, target and
maximum bonus levels for the various executive levels based on competitive data.
For the named Executive Officers, the threshold bonus level is 14% to 24% of
base pay, the target bonus level is 35% to 60% of base pay, and the maximum
bonus level is 49% to 84% of base pay. At the executive level, the primary form
of short-term incentive compensation is a cash bonus pool arrangement, for which
all employees on the Company's system executive payroll are eligible.
Individual Business Segment Pools and a CNG Corporate Pool are established
if the Business Segments or the CNG System attain certain levels of performance.
The Business Segment Pools are calculated as a percent of the eligible base
payroll using the weighted differential between established Business Segment
goals and actual performance. The CNG Corporate Pool is calculated as a percent
of eligible base payroll, using the weighted differential between CNG System
goals and actual performance. CNG Producing's Pool is calculated based on its
actual performance against its goals.
Executives participate in the bonus pools with payout opportunities
determined by actual individual performance and the level of responsibility
within their respective Business Segments and within the CNG System. A pool will
not be established at Corporate unless 90% of the net income goal is achieved
for the CNG System or, for CNG Producing, if 95% of its net income goal is
achieved. If the net income threshold is achieved and the total weighted average
achievement for all goals is 85%, threshold bonus pools are created; at 100% of
goal, target bonus pools are created; and, at 115% or greater of goal
achievement, maximum bonus pools are created. At less than the threshold level,
there are no bonus pools. The performance measures for the CNG Corporate Pool
(weighted as indicated) are based on the System's return on equity vs. peers
(20%), System net income (40%), System controllable operations and maintenance
expenses (30%), and System net cash flow (10%), with specific performance goals
established based on the Company's annual long-range forecast, actual prior year
performance and business plan objectives. Performance targets are set to meet or
exceed the performance of peer companies. The performance measures for CNG
Producing (weighted as indicated) are: net income (40%), cash flow (15%),
full-cycle finding and development costs (20%), lifting costs (20%), and
controllable operations and maintenance expenses (5%). For the last fiscal year,
CNG Corporate achieved 105% of its goals and CNG Producing achieved 97% of its
goals. Based on 1997 performance bonus pools were established at CNG Corporate
of $2,821,700 and at CNG Producing of $576,000.

12
<PAGE> 16

LONG-TERM INCENTIVE COMPENSATION

Under the Long Term Strategic Incentive Program, executives who are driving the
strategy of the Company are granted Restricted Stock and Triannual Non-Qualified
Stock Options in amounts which are intended to be competitive with comparable
employers. Grants under the Long Term Strategic Incentive Program are to be made
every three years. The first grants were made on January 2, 1996.

COMPENSATION CONSULTANT

The Committee utilizes the services of an independent compensation consultant to
assess market relativity of the executive compensation packages. Consistent with
the Company's compensation philosophy, adjustments are made to any executive
compensation components in order to achieve levels of compensation at the median
market position.

TAX MATTERS

Effective for the tax-year ended December 31, 1994, Section 162(m) of the
Internal Revenue Code places certain limits on the deductibility of
non-performance based executive compensation. It is the policy of the Company to
preserve the tax deductibility of compensation to the extent that it is in the
best interest of the Company. Current and anticipated levels of executive
compensation do not subject the Company to the limitations under Section 162(m).

CEO'S COMPENSATION

Mr. Davidson's compensation for 1997 was determined in the general context of
the programs described above. Mr. Davidson's 1997 incentive compensation goals
were based in part on the following measures of the Company's performance
(weighted as shown): System net income (20%), System cash flow (defined as cash
flow from operations less dividends) (5%), return on equity (compared to peer
companies) (10%), System controllable operations and maintenance expense (10%),
credit rating of the Company's long-term debt (10%), price to earnings ratio
(compared to published summary data) (5%), and the continued improvement in
System exploration and production financial performance (10%). In addition, Mr.
Davidson's 1997 incentive compensation goals were based upon his support for CNG
Energy Services Corporation to ensure its success in 1997 (20%), and
implementation of strategic management initiatives (10%). Mr. Davidson's
threshold bonus level is 24% of base pay, his target bonus level is 60% of base
pay and his maximum bonus level is 84% of base pay. Based on the above criteria,
the Committee awarded $400,000 in short-term incentive compensation to Mr.
Davidson for 1997.

S. A. Minter, Chair
J. W. Connolly
P. E. Lego
M. A. McKenna

13
<PAGE> 17

SHAREHOLDER RETURN PERFORMANCE PRESENTATION

Set forth below is a line graph comparing the yearly cumulative total
shareholder return on CNG's Common Stock against the cumulative total return of
the S&P 500 Stock Index and a Natural Gas Industry Index for the period of five
years commencing December 31, 1992, and ended December 31, 1997.
The industry index shown is comprised of the companies listed in the Value
Line Natural Gas Diversified Group. These companies are: Cabot Oil & Gas,
Coastal Corporation, Columbia Gas System, Inc., Consolidated Natural Gas
Company, Eastern Enterprises, El Paso Natural Gas Company, Enron Corporation,
Equitable Resources, Inc., KN Energy, Inc., MAPCO Inc., Mitchell Energy &
Development Corporation, National Fuel Gas Company, Questar Corporation, Seagull
Energy Corporation, Sonat Inc., Southwestern Energy Company, Union Pacific
Resources Group, Inc., and The Williams Companies, Inc.

COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN*

<TABLE>
<CAPTION>
Measurement Period
(Fiscal Year Covered) CNG S&P 500 Value Line
<S> <C> <C> <C>
1992 100 100 100
1993 107 110 122
1994 85 112 114
1995 115 153 153
1996 145 189 191
1997 165 252 218
</TABLE>

<TABLE>
<CAPTION>
1992 1993 1994 1995 1996 1997
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
CNG.................................. $100 $107 $ 85 $115 $145 $165
S&P 500.............................. 100 110 112 153 189 252
Value Line........................... 100 122 114 153 191 218
</TABLE>

* Assumes $100 investment on December 31, 1992, and reinvestment of dividends.

14
<PAGE> 18

NON-EMPLOYEE DIRECTORS' COMPENSATION

Non-employee Directors are currently paid a $24,000 annual retainer, a $2,000
per diem fee for attending each Board meeting, including all Board Committee
meetings held in conjunction with such Board meeting, and a $1,000 per diem fee
for participating in telephonic Board or Board Committee meetings. Committee
Chairpersons receive an additional annual fee of $3,000.
Directors may elect to defer receipt of these payments until after
retirement from the Board. Such payments are deferred in the form of cash
credits or Consolidated Natural Gas Company Common Stock credits. Such stock
credits are valued as Common Stock equivalents equal to the number of shares
that could have been purchased at the closing price on the date the compensation
was earned. As of the date any dividend is paid on the Company's Common Stock, a
credit is made to each participant's deferred account equal to the number of
shares of Common Stock that could have been purchased on such date with the
dividend paid. Amounts deferred in the form of cash credits earn interest,
compounded quarterly, at a rate equal to the closing prime commercial rate at
The Chase Manhattan Bank N.A. on the last day of each quarter. Payments are made
in cash, in a lump sum or in annual installments over a period not exceeding ten
years. The entire undistributed deferred amount will be distributed in a lump
sum upon a participating Director's death.
Directors receive an annual grant of 200 shares of the Company's Common
Stock, subject to restrictions, or the same amount of Consolidated Natural Gas
Company Common Stock credits and options on 1,000 shares of the Company's Common
Stock. Such grants are to be made on the date of the Annual Meeting of
Stockholders. Newly elected Directors will receive an initial grant of 400
shares of the Company's Common Stock, subject to restrictions, or the same
amount of Consolidated Natural Gas Company Common Stock credits and options on
2,000 shares of the Company's Common Stock. Such grants are to be made on the
date of the Director's election to the Board. The restrictions on such stock
shall lapse in 25% installments on the anniversary date of each grant or shall
lapse in total upon the Director's retirement at age 70 or the Director's
ceasing to serve due to death or disability. The Consolidated Natural Gas
Company Common Stock credits are described above.
Effective January 1, 1997, the Board of Directors voted to terminate the
post-retirement retainer for newly elected non-employee Directors and all
current directors elected to waive the post-retirement retainer and receive the
present value of such benefit in deferred stock credits or restricted common
stock of the Company. In the past, the annual retainer paid to non-employee
Directors, as set by the Board of Directors from time to time, was continued to
be paid for life to each non-employee Director retired at age 70, or at an
earlier age due to disability, provided the non-employee Director served a
minimum of four years and agreed to be generally available as a consultant.
Payments under the continued post-retirement retainer arrangement cease at the
death of the Director.
Employee Directors do not receive any compensation for service as
Directors.

HUMAN RESOURCES COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

During 1997, the following Directors served as members of the Human Resources
Committee: S. A. Minter, Chair, J. W. Connolly, P. E. Lego and M. A. McKenna.
The Company now has a Credit Agreement totaling $775 million with a group
of banks. Each participating bank is compensated with a fee of .04% on its
respective commitment amounts.
Currently, PNC Bank, Pittsburgh, Pennsylvania, the subsidiary of PNC Bank
Corp., of which Messrs. Davidson and Simmons are Directors, provides a
commitment of $100 million under the Credit Agreement. Mellon Bank, N.A.,
Pittsburgh, Pennsylvania, of which Mr. Connolly is a Director, provides a
commitment of $100 million under the Credit Agreement. Key Bank, NA, Cleveland,
Ohio, the subsidiary of KeyCorp, of which Mr. Minter is a Director, provides a
commitment of $90 million under the Credit Agreement. There were no borrowings
under the Agreement in 1997.

15
<PAGE> 19

BENEFIT PLANS

LIFE INSURANCE AND RELATED BENEFIT PLANS

The Company maintains a program composed of Split Dollar Life Insurance Plans
and Supplemental Death Benefit Plans for employees on the executive payroll of
the Company and its subsidiaries, as well as non-employee Directors, which
provides death benefits to beneficiaries of those individuals. There were 146
eligible employees on December 31, 1997, and 80 were participating. Five
non-employee Directors also were participating. The plans are under the general
supervision of the Human Resources Committee of the Board. Continuation of the
plans beyond retirement requires the Committee's approval. The costs for the
Split Dollar Life Insurance Plans are shared by the Company and the
participants. Each year an employee participant pays a premium based on age and
amount of individual coverage, which is approximately twice annual salary. Each
year, Director participants pay a premium based on age and amount of individual
coverage. The Company pays all additional premiums and expects to receive
proceeds approximately equal to its investment in the policy through the total
coverage exceeding the participant's individual coverage. The Supplemental Death
Benefit Plans provide for payments to a deceased participant's beneficiaries
over a period of years.

RETIREMENT PROGRAMS

A non-contributory Pension Plan is maintained for employees who are not
represented by a recognized union, including Officers of the Company and its
subsidiaries. On December 31, 1997, all 2,908 eligible employees of the Company
and its subsidiary companies were participating in the Pension Plan.
The Company also maintains an unfunded Short Service Supplemental
Retirement Plan for certain management employees whose commencement of service
with the Company occurred after the employee had acquired experience of
considerable value to the Company and who will have less than 32 years of
service at normal retirement.
The following table illustrates maximum annual benefits--including any
supplemental payment described above but before being reduced by the required
offset--at normal retirement date (age 65) on the individual life annuity basis
for the indicated levels of final average annual salary and various periods of
service.

PENSION PLAN TABLE

<TABLE>
<CAPTION>
- - ---------------------------------------------------------------------------------------------------------------
Annual Pension Benefit for Years of Service Indicated
--------------------------------------------------------------------
Average Annual Salary 15 20 25 35 40
<S> <C> <C> <C> <C> <C>
- - ---------------------------------------------------------------------------------------------------------------
$100,000............................ $ 34,000 $ 45,300 $ 55,000 $ 59,500 $ 68,000
150,000............................ 51,000 68,000 82,500 89,300 102,000
200,000............................ 68,000 90,700 110,000 119,000 136,000
250,000............................ 85,000 113,300 137,500 148,800 170,000
300,000............................ 102,000 136,000 165,000 178,500 204,000
350,000............................ 119,000 158,700 192,500 208,300 238,000
400,000............................ 136,000 181,300 220,000 238,000 272,000
450,000............................ 153,000 204,000 247,500 267,800 306,000
500,000............................ 170,000 226,700 275,000 297,500 340,000
550,000............................ 187,000 249,300 302,500 327,300 374,000
600,000............................ 204,000 272,000 330,000 357,000 408,000
650,000............................ 221,000 294,700 357,500 386,800 442,000
700,000............................ 238,000 317,300 385,000 416,500 476,000
- - ---------------------------------------------------------------------------------------------------------------
</TABLE>

The 1997 salaries, projected service to age 65, and estimated annual
retirement benefits on the individual life form of annuity, assuming
continuation of their December 1997 salaries until age 65 for each of the
individuals in the Summary Compensation table, are as follows:

16
<PAGE> 20

ESTIMATED ANNUAL RETIREMENT BENEFITS

<TABLE>
<CAPTION>
- - ---------------------------------------------------------------------------------------------------------------
Estimated Annual
Years of Years of Retirement
1997 Service at Service Benefits
Name Salary Year-End 1997 at Age 65 at Age 65
<S> <C> <C> <C> <C>
- - ---------------------------------------------------------------------------------------------------------------
G. A. Davidson, Jr.............................. $632,650 31 37 $398,379
S. R. McGreevy.................................. 165,800 15 33 87,260
H. P. Riley..................................... 269,335 2 6 40,312
D. M. Westfall.................................. 245,800 28 43 177,443
S. E. Williams.................................. 254,570 23 39 164,604
- - ---------------------------------------------------------------------------------------------------------------
</TABLE>

The Company also maintains a Supplemental Retirement Benefit Plan under
which payments may be made, at the sole discretion of the Human Resources
Committee of the Board, to individuals comprising the executive payroll. As of
December 31, 1997, there were 146 potentially eligible employees. The decision
to grant a Supplemental Retirement Benefit is based on a review of the retiring
employee's total available benefits. Payments under such plan during 1997
amounted to $453,927. The maximum annual supplemental annuity under this plan is
10% of an individual's final average annual salary. Assuming continuation of
their December 1997 salaries until age 65, the individuals named in the Summary
Compensation table would be eligible to receive the following maximum annual
supplemental retirement benefits: Mr. Davidson, $63,820; Mr. McGreevy, $16,690;
Mr. Riley, $27,170; Mr. Westfall, $25,080 and Mr. Williams, $25,680.
The benefits described above have not been reduced by the limitations
imposed on qualified plans by the Internal Revenue Code. As permitted by the
Internal Revenue Code, the Board of Directors has adopted a policy whereby
supplemental payments may be made, as necessary, to maintain the benefit levels
earned under the benefit plans.

COMPLIANCE WITH SECTION 16(A) OF THE SECURITIES EXCHANGE ACT

Based on the Company's review of copies of all Section 16(a) forms filed by the
Officers and Directors of the Company, the Company believes that in 1997 there
was compliance with all filing requirements applicable to its Officers and
Directors.

PROPOSAL 2
RATIFICATION OF APPOINTMENT OF INDEPENDENT ACCOUNTANTS

Price Waterhouse LLP has audited the accounts of the Company and its
subsidiaries since 1943. On recommendation of the Audit Committee, the Board of
Directors has, subject to ratification by the stockholders, appointed Price
Waterhouse LLP to audit the accounts of the Company and its subsidiaries for the
fiscal year 1998. Audit fees to Price Waterhouse LLP in 1997 incurred by the
Company and its subsidiaries were approximately $1,495,600. A representative of
Price Waterhouse LLP will be present at the Meeting to respond to appropriate
questions and will have an opportunity to make a statement if he or she desires
to do so. Accordingly, the following resolutions will be offered at the Meeting:
RESOLVED, That the appointment, by the Board of Directors of the Company,
of Price Waterhouse LLP to audit the accounts of the Company and its subsidiary
companies for the fiscal year 1998, effective upon ratification by the
stockholders be, and it hereby is, ratified; and
FURTHER RESOLVED, That a representative of Price Waterhouse LLP shall
attend the next Annual Meeting and any special meetings of stockholders that may
be held in the interim.

VOTE NEEDED FOR APPOINTMENT OF INDEPENDENT ACCOUNTANTS
An affirmative vote of the holders of a majority of the Company's Common Stock,
represented in person or by proxy and entitled to vote at the Meeting, is
necessary for ratification. If the stockholders do not ratify the appointment of
Price Waterhouse LLP, the selection of independent accountants will be
reconsidered by the Audit Committee and the Board of Directors.

BOARD RECOMMENDATION
The Board recommends that stockholders vote FOR Proposal 2, and the accompanying
proxy will be so voted, unless a contrary specification is made.

17
<PAGE> 21

PROPOSAL 3
STOCKHOLDER'S PROPOSAL CONCERNING RIGHTS PLAN

Amalgamated Bank of New York, LongView Collective Investment Fund, 11-15 Union
Square West, New York, New York, which owns 26,200 shares of the Company's
Common Stock, has submitted the resolution set forth below for inclusion in this
Proxy Statement for the Company's 1998 Annual Meeting of Shareholders.

THE STOCKHOLDER'S PROPOSAL
SHAREHOLDER RIGHTS PLAN RESOLUTION
"RESOLVED: That the shareholders of Consolidated Natural Gas Company ("CNG" or
the "Company") request the Board of Directors to redeem the shareholder rights
previously issued unless such issuance is approved by the affirmative vote of
shareholders, to be held as soon as may be practicable."

The Stockholder's Supporting Statement
In 1995, the CNG Board of Directors issued, without shareholder approval,
certain shareholder rights (the "rights") pursuant to a shareholder rights plan.
We strongly believe that such rights are a type of anti-takeover device,
commonly known as a poison pill, which injures shareholders by reducing
management accountability and adversely affecting shareholder value.
The shareholders of the Company believe the terms of the rights are
designed to discourage or thwart an unwanted takeover of the Company. While
management and the Board of Directors should have appropriate tools to ensure
that all shareholders benefit from any proposal to acquire the Company, the
shareholders do not believe that the future possibility of a takeover justifies
the unilateral imposition of such a poison pill.
Rather, we believe that the shareholders should have the right to vote on
the necessity of such a powerful tool, which could be used to entrench existing
management. Rights plans like the Company's have become increasingly unpopular
in recent years.
The negative effects of poison pill rights plans on the trading value of
companies' stock have been the subject of extensive research. A 1986 study
(covering 245 companies adopting poison pills between 1983 and July 1986) was
prepared by the Office of the Chief Economist of the U.S. Securities and
Exchange Commission on the effect of poison pills on the wealth of target
shareholders. It states that "empirical tests, taken together, show that poison
pills are harmful to target shareholders, on net." A 1992 study by Professor
John Pound of Harvard's Corporate Research Project and Lilli A. Gordon of the
Gordon Group found a correlation between high corporate performance and the
absence of poison pills.
We believe that such an important corporate governance practice, one that
can have a significant adverse impact on shareholder value, should be eliminated
or, at the very least, be voted on by shareholders.
Last year, this resolution received the support of 54% of the shares that
were voted (including yeas, nays and abstentions), but it has not been
implemented. We therefore submit this shareholder proposal based on our belief
that the unilateral and undeniable undemocratic adoption of the rights plan by
the Company is unjustified, that the continued existence of such a rights plan
by the Company is unjustified and not in the best interests of the shareholders.
We urge you to vote FOR this resolution!

18
<PAGE> 22

MANAGEMENT'S COMMENTS
The Board of Directors adopted the shareholder protection rights plan (the
"Rights Plan") in 1995 because the Board believed the Rights Plan would better
enable the Board to represent the interests of all shareholders in the event of
a hostile effort to acquire Consolidated Natural Gas Company and take advantage
of its shareholders.
The Board met to consider the proponent's proposal in view of its adoption
at last year's annual meeting. After a thorough review of the matter, the Board
unanimously believes the Rights Plan should be maintained. The Board considered
the arguments of the proponents of this proposal and discussed other companies'
experience with similar plans. Based on an in-depth study of the matter, the
Board continues to believe that the Rights Plan serves the interest of the
shareholders. If there were an offer to purchase the Company on terms that were
unfair to some or all shareholders, the Board believes the Rights Plan would
encourage the bidder to negotiate with the Board. The Board also believes that
shareholder rights plans have not historically prevented fair bids, but have
been a factor in increasing the value paid to shareholders in hostile
acquisitions.
In November 1997, Georgeson & Company Inc., New York, New York, a
nationally recognized proxy solicitation and investor relations firm, after
extensive analysis of takeover transactions, found that shareholders of
companies with rights plans received $13 billion in additional takeover premiums
during the five-year period from 1992-1996, and shareholders of companies
without rights plans gave up $14.5 billion in potential value. The Georgeson
study also found that premiums paid to acquire target companies with rights
plans were on an average 8 percentage points higher than premiums paid for
target companies that did not have rights plans; the presence of a rights plan
at a target company did not increase the likelihood of the defeat of a hostile
takeover bid nor the withdrawal of a friendly bid; and rights plans did not
reduce the likelihood that a company would become a takeover target: the
takeover rate was similar for companies with and without rights plans.
The Board specifically examined its fiduciary responsibilities under
Delaware law when it adopted the Rights Plan in November 1995 and did so again
in light of the proponent's proposal. It is important to note that the Company's
Board is an independent board, consisting of seven outside directors and one
inside director, providing further assurance that the Rights Plan will not be
used for entrenchment purposes. The Board unanimously believes the Rights Plan
provides a valuable and necessary means for protecting the interests of all of
the shareholders and maximizing the value of their investments in the Company.
Based on the Board's collective business experience and knowledge of the
Company, it believes that the adoption of the Rights Plan was a valid exercise
of its fiduciary obligations to all stockholders, and is in accord with the
Board's responsibility under Delaware law to manage and direct the management of
the Company's business and affairs. The Board does not believe that the Rights
Plan will deter an acquisition offer that adequately reflects the underlying
value of the Company and that is fair to all stockholders, nor will it deter the
initiation of a proxy contest.

VOTE NEEDED FOR APPROVAL OF THE PROPOSAL
Approval of this proposal requires an affirmative vote of the holders of a
majority of the shares present in person or represented by proxy and entitled to
vote. Abstentions are counted in tabulations of the votes cast on proposals
presented to stockholders. Broker non-votes are not counted for purposes of
determining whether a proposal has been approved.

BOARD RECOMMENDATION
The Board recommends that stockholders vote AGAINST Proposal 3, and the
accompanying proxy will be so voted, unless a contrary specification is made.

19
<PAGE> 23

OTHER MATTERS

PROCEDURE FOR SUBMISSION OF 1999 STOCKHOLDER PROPOSALS
The 1999 Annual Meeting of Stockholders will be held on Tuesday, April 13, 1999.
Proposals by stockholders for inclusion in the 1999 Annual Meeting Proxy
Statement must be received by the Corporate Secretary, Consolidated Natural Gas
Company, CNG Tower, 625 Liberty Avenue, Pittsburgh, Pennsylvania 15222-3199,
prior to November 3, 1998. All such proposals are subject to the applicable
rules and requirements of the Securities and Exchange Commission.

OTHER BUSINESS

The Board of Directors does not intend to bring any business before the Meeting
other than that listed in the foregoing Notice and is not aware of any business
intended to be presented to the Meeting by any other person. Should other
matters properly come before the Meeting, the persons named in the accompanying
proxy will vote said proxy in such manner as they may, in their discretion,
determine.

/s/ LAURA J. McKEOWN
--------------------
Laura J. McKeown
Secretary

February 23, 1998

20
<PAGE> 24

NOTE: YOUR SHARES CANNOT BE VOTED UNLESS YOU SIGN AND RETURN YOUR PROXY CARD,
GIVE YOUR PROXY BY CALLING THE TOLL-FREE TELEPHONE NUMBER, OR ATTEND THE
MEETING AND VOTE IN PERSON.

APPENDIX I
CONSOLIDATED NATURAL GAS COMPANY
1997 FINANCIAL STATEMENTS AND NOTES
(ENCLOSED)
<PAGE> 25

CONSOLIDATED NATURAL GAS COMPANY
CNG Tower
625 Liberty Avenue
Pittsburgh, Pennsylvania 15222-3199

GAS DISTRIBUTION
The East Ohio Gas Company
Cleveland, Ohio

The Peoples Natural Gas Company
Pittsburgh, Pennsylvania

Virginia Natural Gas, Inc.
Norfolk, Virginia

Hope Gas, Inc.
Clarksburg, West Virginia

GAS TRANSMISSION
CNG Transmission Corporation
Clarksburg, West Virginia

EXPLORATION AND PRODUCTION
CNG Producing Company
New Orleans, Louisiana

ENERGY MARKETING SERVICES
CNG Energy Services Corporation
Pittsburgh, Pennsylvania

INTERNATIONAL
CNG International Corporation
Reston, Virginia

LOGO
<PAGE> 26

CONSOLIDATED
CNG NATURAL GAS
COMPANY

CONSOLIDATED 1997 Financial
CNG NATURAL GAS Report
COMPANY

CONSOLIDATED
CNG NATURAL GAS
COMPANY

CONSOLIDATED
CNG NATURAL GAS
COMPANY Appendix I
<PAGE> 27

TABLE OF CONTENTS

<TABLE>
<CAPTION>
Page
----
<S> <C>
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 1
Selected Financial Data..................................... 18
Report of Independent Accountants........................... 19
Consolidated Statement of Income for the Years 1995 through
1997...................................................... 21
Consolidated Balance Sheet at December 31, 1996 and 1997.... 22
Consolidated Statement of Cash Flows for the Years 1995
through 1997.............................................. 24
Notes to Consolidated Financial Statements.................. 25
</TABLE>
<PAGE> 28

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

NET INCOME
Net income in 1997 was $304.4 million, or $3.21 a share, compared with net
income of $298.3 million, or $3.17 a share, in 1996. Net income in 1995 was
$21.3 million, or $.23 a share. Basic earnings per share reported for each year
reflects the Company's adoption of Statement of Financial Accounting Standards
(SFAS) No. 128 (see page 4, "New Accounting Standards").
Earnings for 1997, 1996 and 1995 include special charges in each year.
During the fourth quarter of 1997, the Company recorded a non-cash charge to
write down the cost of its Canadian oil producing properties, amounting to $6.7
million after taxes, or $.07 a share. Excluding this item, net income for 1997
would have been $311.1 million, or $3.28 a share. Excluding the impact of
charges related to workforce reduction programs totaling $9.9 million after
taxes, or $.10 a share, 1996 net income would have been $308.2 million, or $3.27
a share. The Company recorded non-cash charges during 1995 to write down the
cost of gas and oil producing properties amounting to $145.0 million after
taxes, or $1.56 a share, and to write down coal properties amounting to $20.3
million after taxes, or $.22 a share. Also in 1995, the Company recorded charges
totaling $25.6 million after taxes, or $.27 a share, for workforce reductions.
Excluding these special items, net income for 1995 would have been $212.3
million, or $2.28 a share. Reference is made to Notes 4 and 5 to the
consolidated financial statements, page 30, for details of these special
charges.

1997
The favorable impact of higher gas and oil production and continued cost
containment efforts more than offset the effects of warmer weather and lower
average wellhead prices for gas and oil. Weather in the Company's retail service
areas was 1.9% colder than normal and 4.3% warmer than 1996. Normal weather
represents a measure of temperature experienced over an historical time frame,
the length of which may differ depending on the regulatory jurisdiction.

1996
Higher wellhead prices for natural gas and oil, increased gas and oil
production, colder weather, cost controls and the full year impact of new rates
in place for most of the Company's gas distribution customers contributed to the
improved results. Weather in the Company's retail service areas was 5.6% colder
than normal and 5.5% colder than 1995.

1995
The favorable effects of new rates in place for most of the Company's gas
distribution and transmission customers, colder weather and lower aggregate wage
and benefit costs in the latter part of the year resulting from the workforce
reduction programs more than offset the impact of low wellhead prices for
natural gas and lower gas and oil production.

OPERATING REVENUES
Operating revenues include revenues from gas and oil sales, transportation and
storage of gas, brokering activities, by-product operations and wholesale
electric sales. Total operating revenues in 1997 were $5,710.0 million, an
increase of $1,915.7 million compared to $3,794.3 million in 1996. Significantly
increased sales of gas and electricity by the energy marketing services
operations was the primary reason for the revenue growth. Consistent with
industry conditions, these operations generate high sales volumes at low
margins.
Regulated gas sales revenues of $1,851.0 million in 1997 were up $98.8
million compared to 1996, despite sales volumes decreasing 22.0 billion cubic
feet (Bcf) to 272.0 Bcf. The decline in volumes was due to warmer weather and
the effect of the displacement of sales volumes to other suppliers, including
CNG

1
<PAGE> 29

Retail Services Corporation (CNG Retail). Sales revenues attributable to the
Company's residential and commercial customers increased during 1997 as higher
average sales rates, reflecting the recovery of previously deferred purchased
gas costs, more than offset reduced volumes compared to 1996. The impact of
lower sales volumes for the Company's industrial customers more than offset
higher average sales rates for that customer class during 1997.
Nonregulated gas sales revenues increased $1,246.6 million in 1997 to
$2,339.1 million, with sales volumes increasing 411.6 Bcf to 807.7 Bcf. The
increases in both revenues and volumes during 1997 were attributable chiefly to
the energy marketing services operations. The increases also reflect higher gas
production at CNG Producing Company (CNG Producing).
Gas transportation and storage revenues rose $14.4 million in 1997 compared
to the prior year, to $479.5 million, reflecting both higher gas transportation
and storage service revenues. Wholesale electricity sales by the energy
marketing services operations increased $485.1 million in 1997 due chiefly to
higher volumes. Other operating revenues increased $70.8 million in 1997 to
$445.8 million. Revenues from oil brokering were up $39.7 million, while
revenues from the sale of oil and condensate production increased $33.5 million.
In both cases, the impact of higher volumes more than offset a decline in oil
prices.
Total operating revenues in 1996 increased $487.0 million from $3,307.3
million in 1995. Regulated gas sales revenues in 1996 increased $154.8 million
to $1,752.2 million, with sales volumes increasing 4.1 Bcf to 294.0 Bcf due
mainly to colder weather. Nonregulated gas sales revenues increased $94.8
million in 1996, while sales volumes decreased 160.5 Bcf to 396.1 Bcf. The
effect of higher prices, coupled with the impact of higher production by the
exploration and production operations, more than offset the effect of reduced
transaction volumes of the energy marketing services component. Gas
transportation and storage revenues of $465.1 million in 1996 were up $8.7
million over 1995. The increase was due to higher transportation revenues as a
result of increased volumes and rates. Wholesale electricity revenues of the
energy marketing services component were up $87.7 million in 1996 due to higher
quantities of electricity sold. Other operating revenues increased $141.0
million in 1996, to $375.0 million, due chiefly to an increase of $108.8 million
in revenues from oil and condensate production and brokering.

OPERATING EXPENSES
Operating expenses, including income taxes, increased to $5,311.8 million in
1997, compared to $3,402.1 million and $3,160.8 million in 1996 and 1995,
respectively. Excluding the impact of impairments of gas and oil producing
properties in 1997 and 1995 and workforce reduction charges in 1996 and 1995,
operating expenses would have been $5,305.1 million, $3,392.2 million and
$2,990.2 million for the years 1997, 1996 and 1995, respectively.
Purchased gas consistently represents the largest operating expense
category for the Company. Purchased gas costs were $2,960.2 million in 1997,
$1,615.0 million in 1996 and $1,590.1 million in 1995. This expense is
influenced primarily by changes in gas sales requirements, the price and mix of
gas supplies, and the timing of recoveries of deferred purchased gas costs.
Increased volume requirements in connection with nonregulated gas sales and the
recognition of previously deferred purchased gas costs contributed to the
increase in 1997. For 1996, the effect of higher average purchase prices more
than offset the impact of decreased volume requirements in connection with
nonregulated gas sales and the deferral of purchased gas costs by the regulated
subsidiaries.
Electricity, liquids and capacity purchased expense includes the cost of
electricity, oil, condensate and by-products purchased for resale and pipeline
capacity not associated with gas purchased. This expense increased $523.0
million in 1997 and $193.1 million in 1996 due primarily to electricity
purchased for resale by the energy marketing services component and oil
purchased for resale by CNG Producing.
Excluding the effect in 1996 of workforce reduction charges, combined
operation and maintenance expense increased $24.4 million in 1997. This increase
was due largely to adjustments of reserves for pipeline settlements and
receivables recorded during 1997 by the energy marketing services component, in
addition to higher royalty expense and production-related costs. These costs
were partially offset by lower employment costs. Maintenance expense increased
slightly in 1997.

2
<PAGE> 30

Excluding the effect of 1996 and 1995 workforce reduction charges totaling
$15.2 million and $42.6 million, respectively, combined operation and
maintenance expense increased $77.2 million in 1996. This increase was due in
large part to increased royalty expense, partially offset by lower employee-
related costs and reductions in certain administrative expenses. Maintenance
expense increased $4.2 million in 1996 to $90.1 million.
Total depreciation and amortization expense increased $25.9 million in 1997
and $47.6 million in 1996 due largely to higher gas and oil production volumes
each year. Depreciation expense for the regulated subsidiaries increased in both
1997 and 1996 due principally to the increased level of plant investment.
Taxes, other than income taxes, were up $4.8 million in 1997 due in part to
higher excise taxes, and decreased $.7 million in 1996 due largely to lower
excise and payroll taxes.
Income taxes decreased $8.8 million in 1997, due largely to a lower
effective tax rate, and increased $152.8 million in 1996. The 1996 increase was
due to higher pretax earnings compared to 1995.

OTHER INCOME
Total other income was $13.5 million in 1997, compared to $9.3 million in 1996
and total other deductions of $20.5 million in 1995. Excluding the write-down of
coal properties of $31.3 million, total other income in 1995 would have been
$10.8 million. Interest revenues decreased slightly in 1997, and declined $6.8
million in 1996 compared to 1995 due largely to the lower level of temporary
cash investments in 1996. The increase in "Other-net" in 1997 of $4.3 million
compared to 1996 is due largely to a charge of $5.0 million recognized in
connection with an early extinguishment of debt in December 1996. Increased
earnings from the Company's equity investments and losses related to minor
property dispositions at certain regulated subsidiaries in 1995 that did not
recur in 1996, partially offset by the debt extinguishment charge, were the
primary reasons for the increase in "Other-net" of $5.4 million in 1996 compared
to 1995.

INTEREST CHARGES
Interest on long-term debt increased $3.1 million in 1997. This increase was due
largely to a full year of interest expense related to the $300 million of
debentures issued in the fourth quarter of 1996, partially offset by the effects
of the redemption in early 1997 of $100 million of debentures and the early
extinguishment of $53.1 million of debt in late 1996. Interest on long-term debt
increased $6.0 million in 1996 due primarily to debenture sales of $150 million
each in April 1995, October 1996 and December 1996. Other interest expense
increased $1.9 million in 1997. Other interest expense declined $7.5 million in
1996 due largely to lower interest expense related to customer refunds.

FOURTH QUARTER RESULTS
Net income for the fourth quarter of 1997 was $89.4 million compared to $88.0
million in 1996. On a basic earnings per share basis, the 1997 quarter was $.94
compared with $.93 in 1996. However, the 1997 fourth quarter reflects a special
charge for the impairment of oil producing properties totaling $6.7 million
after taxes, or $.07 per share, while the 1996 quarter includes special charges
for workforce reductions totaling $7.8 million after taxes, or $.08 per share.
The Company's 1997 average gas wellhead price was $2.54 per thousand cubic feet
(Mcf), down $.08 per Mcf, and average oil wellhead prices declined $2.90 per
barrel, to $15.69. These negative factors were partially offset by the impact of
weather that was 2.2% colder than in 1996.

3
<PAGE> 31

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

<TABLE>
<CAPTION>
QUARTERS ENDED DECEMBER 31, 1997 1996
- - -----------------------------------------------------------------------------------
(In Millions)
<S> <C> <C>
Operating revenues.......................................... $ 1,850.1 $ 1,229.2
Operating expenses.......................................... (1,689.4) (1,066.4)
--------- ---------
Operating income before income taxes........................ 160.7 162.8
Income taxes................................................ (40.8) (46.1)
Other income/expenses-net................................... (30.5) (28.7)
--------- ---------
Net income.................................................. $ 89.4 $ 88.0
========= =========
Earnings per common share--basic (in dollars)............... $.94 $.93
Earnings per common share--diluted (in dollars)............. $.92 $.91
- - -----------------------------------------------------------------------------------
</TABLE>

NEW ACCOUNTING STANDARDS
In 1997, the Financial Accounting Standards Board (FASB) issued SFAS No. 128,
"Earnings per Share," which established new requirements for computing and
presenting earnings per share. The Company has adopted the provisions of SFAS
No. 128 for the year ended December 31, 1997, and has restated earnings per
share amounts for all prior periods presented in conformity with the new
standard. The adoption of SFAS No. 128 did not have a material effect on the
Company's earnings per share for any of the periods presented. Reference is made
to Note 2 to the consolidated financial statements, page 28, regarding SFAS No.
128.
Also in 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive
Income," and SFAS No. 131, "Disclosures about Segments of an Enterprise and
Related Information." SFAS No. 130 establishes standards for the reporting and
display of comprehensive income and its components. The Company is required to
adopt the provisions of SFAS No. 130 beginning with its consolidated financial
statements for the three months ending March 31, 1998. SFAS No. 131 requires
certain disclosures about segment information in interim and annual financial
statements and related information about products and services, geographic areas
and major customers. The Company must adopt the provisions of SFAS No. 131 for
its consolidated financial statements for the year ending December 31, 1998. The
adoptions of SFAS Nos. 130 and 131 are not expected to have a material effect on
the Company's financial position, results of operations or cash flows.

COMPONENTS OF THE BUSINESS
Due to the regulated nature of the distribution and transmission components of
the Company's business, operating results can be affected by regulatory delays
when price increases are sought through general rate filings to recover certain
higher costs of operations. Weather is also an important factor since a major
portion of the gas sold or transported by the distribution and transmission
operations is ultimately used for space heating.

4
<PAGE> 32

Operating results for each of the Company's business components follow.
Reference is made to Note 19 to the consolidated financial statements, page 45,
for additional disaggregated information.
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
OPERATING INCOME BEFORE INCOME TAXES 1997(a) 1996(b) 1995(c)
- - -----------------------------------------------------------------------------------------
(In Millions)
<S> <C> <C> <C>
Distribution................................................ $266.6 $258.4 $ 207.5
Transmission................................................ 178.4 178.8 150.4
Exploration and production.................................. 142.8 133.2 (200.5)
Energy marketing services................................... (17.1) (9.1) (5.7)
Other(d).................................................... (9.3) (3.2) 2.9
Corporate and eliminations.................................. (16.2) (10.1) (5.1)
------ ------ -------
Total..................................................... $545.2 $548.0 $ 149.5
====== ====== =======
</TABLE>

(a) Amount for the exploration and production operations includes the impact of
the write-down of oil producing properties in Canada amounting to $10.4
million.

(b) Amounts for the distribution, transmission, exploration and production,
energy marketing services and corporate components include the effect of
workforce reduction charges totaling $8.2 million, $5.1 million, $.6
million, $.3 million and $1.0 million, respectively.

(c) Amount for the exploration and production operations includes the impact of
the write-down of gas and oil producing properties in the United States
amounting to $226.2 million. Amounts for the distribution, transmission,
exploration and production, energy marketing services and corporate
components include the effect of workforce reduction charges totaling $22.3
million, $6.0 million, $7.7 million, $.5 million and $4.6 million,
respectively.

(d) Includes Consolidated LNG, CNG Research and CNG Coal. Amounts for 1997 and
1996 include CNG International and CNG Products and Services. Amounts for
1997 also include CNG Retail.
- - --------------------------------------------------------------------------------

DISTRIBUTION
"Distribution" represents the results of the four retail gas distribution
subsidiaries, including their minor gas and oil production activities.
Sales growth in the Company's residential service areas in Ohio,
Pennsylvania and West Virginia has generally been limited since such areas have
experienced minimal population growth, and the vast majority of households in
these areas already use natural gas for space heating. Opportunity for growth in
the retail sales market is expected to continue at Virginia Natural Gas, Inc.
(Virginia Natural Gas), due to customer conversions from other energy sources
and the past and potential future expansion of its service territory. Since the
Company's acquisition of this subsidiary in 1990, it has experienced an annual
customer growth rate of about 4%, compared to a growth rate of less than 1% for
the other distribution subsidiaries.
Similar to the unbundling in recent years of the services provided by gas
pipeline companies, gas distribution companies are adapting to the deregulation
and unbundling of the retail energy market. Under open access programs, natural
gas suppliers other than the local gas utility can use the utility's existing
lines to deliver gas to customers.
In early 1997, the Company formed a new nonregulated subsidiary, CNG
Retail, to market natural gas, electricity, and consumer products and services
to residential, commercial and small industrial customers, including those
within the Company's traditional service territories. CNG Retail is expected to
enable the Company to take advantage of emerging deregulated energy markets for
both gas and electricity.
During the spring of 1997, The Peoples Natural Gas Company (Peoples Natural
Gas) opened its system in Pennsylvania to customer choice. In addition, on July
2, 1997, the Public Utilities Commission of Ohio (PUCO) approved The East Ohio
Gas Company's (East Ohio Gas) "Energy Choice" pilot program which will allow
approximately 15% of East Ohio Gas's residential and small business customers
the opportunity to purchase their natural gas from competing suppliers, if they
so choose.

5
<PAGE> 33

DISTRIBUTION OPERATING INCOME BEFORE INCOME TAXES

1997
Excluding workforce reduction charges during 1996, operating income before
income taxes of $266.6 million in 1997 was unchanged from the prior year. The
effect of warmer weather in 1997 offset the impact of lower operation and
maintenance expenses during the year. Weather in the Company's retail service
areas was 1.9% colder than normal but 4.3% warmer than 1996.

1996
Excluding workforce reduction charges amounting to $8.2 million in 1996 and
$22.3 million in 1995, operating income before income taxes for those years
would have been $266.6 million and $229.8 million, respectively. Improved
results for 1996 reflect colder weather, cost control efforts and the full year
impact of general rate increases that went into effect in the latter part of
1995 at Peoples Natural Gas, Hope Gas, Inc. (Hope Gas) and East Ohio Gas.
Weather in the Company's retail service areas was 5.5% colder than 1995 and 5.6%
colder than normal.

1995
Excluding workforce reduction charges, operating income before income taxes in
1995 was up $70.8 million. In addition to the general rate increases placed into
effect in late 1994 and 1995, colder weather, the addition of new customers,
higher transport volumes and lower wage and benefit costs in the latter part of
the year due to the workforce reduction programs contributed favorably to 1995
results. Weather was 2.2% colder than 1994 and .5% colder than normal.

DISTRIBUTION OPERATING REVENUES
Operating revenues increased $121.1 million in 1997, to $2,026.6 million. Gas
sales revenues increased $101.1 million as higher average sales rates,
reflecting the recovery of previously deferred purchased gas costs, more than
offset the effect of reduced sales volumes. Gas transportation and storage
revenues increased $21.5 million in 1997 due to both higher volumes and rates.
Revenues in 1996 increased $160.3 million to $1,905.5 million. Gas sales
revenues were up $152.3 million reflecting both higher average sales prices and
higher sales volumes. Average sales prices increased due to the impact of both
higher unit purchased gas costs passed through to customers and higher rates in
place for most of the Company's distribution customers. Colder weather was a
major factor in the increased sales volumes. Gas transportation and storage
revenues increased $10.1 million resulting from both higher volumes and rates.

DISTRIBUTION THROUGHPUT
Since distribution sales largely represent retail sales for space heating,
changes in sales volumes from one period to another are primarily a function of
the weather. In addition to sales service, the distribution operations provide
gas transportation services to a wide range of customers, primarily commercial
and industrial end users. Therefore, the volume of gas transported can be
affected by changes in both economic and market conditions.
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
DISTRIBUTION THROUGHPUT 1997 1996 1995
- - -------------------------------------------------------------------------------------
(In Billion Cubic Feet)
<S> <C> <C> <C>
Sales....................................................... 272.7 294.2 289.9
Transportation.............................................. 189.4 174.2 164.8
----- ----- -----
Throughput............................................. 462.1 468.4 454.7
===== ===== =====
- - -------------------------------------------------------------------------------------
</TABLE>

Warmer weather and the effect of the displacement of sales volumes to other
suppliers, including CNG Retail, were the reasons for the decrease in gas sales
volumes compared to 1996. Residential gas sales volumes decreased 10.9 Bcf, to
207.8 Bcf, in 1997. Commercial sales decreased 7.1 Bcf while volumes transported
to these customers were up 9.0 Bcf. Deliveries to industrial customers were
lower in 1997, decreasing .5 Bcf to 138.3 Bcf. Sales to industrial customers
declined 2.6 Bcf to 4.3 Bcf, while transporta-

6
<PAGE> 34

tion volumes increased 2.1 Bcf to 134.0 Bcf. Transportation to off-system
customers increased 4.1 Bcf in 1997.
In 1996, colder weather and the net addition of approximately 17,000
residential and commercial customers contributed to the slight increase in gas
sales volumes compared to 1995. Residential gas sales volumes increased 6.2 Bcf,
to 218.7 Bcf, in 1996. Commercial sales decreased 3.0 Bcf while volumes
transported to these customers were up 7.2 Bcf. Deliveries to industrial
customers were higher in 1996, increasing .6 Bcf to 138.8 Bcf. Sales to
industrial customers declined .4 Bcf to 6.9 Bcf, while transportation volumes
increased 1.0 Bcf to 131.9 Bcf. Transportation to off-system customers increased
1.2 Bcf in 1996.

TRANSMISSION
"Transmission" includes the results of the gas transmission, storage, by-product
and certain other activities of CNG Transmission Corporation (CNG Transmission).
Gas and oil production activities of CNG Transmission are included in
exploration and production operations.

TRANSMISSION OPERATING INCOME BEFORE INCOME TAXES

1997
Excluding workforce reduction charges in 1996, operating income before income
taxes declined $5.5 million in 1997, to $178.4 million. However, the 1997
results include a charge amounting to $5.8 million recognized in the fourth
quarter in connection with CNG Transmission's withdrawal from participation in a
gas storage development project.

1996
Excluding workforce reduction charges of $5.1 million in 1996 and $6.0 million
in 1995, operating income before income taxes for those years would have been
$183.9 million and $156.4 million, respectively. Cost control efforts and
increased gas transportation and by-products revenues contributed to the
improved results in 1996.

1995
Excluding workforce reduction charges, operating income before income taxes
increased $10.1 million in 1995. Higher rates resulting from CNG Transmission's
general rate filing, which became effective July 1, 1994, and cost controls were
the major factors for the improved results in 1995.

TRANSMISSION OPERATING REVENUES
Total operating revenues declined $16.4 million in 1997, to $487.0 million. Gas
transportation revenues declined $15.7 million due to both lower volumes and
rates, and revenues from the sale of by-products decreased $3.7 million due
primarily to lower sales rates. These decreases were partially offset by an
increase of $2.8 million in gas storage service revenues.
Total operating revenues were $32.4 million higher in 1996 compared to
1995. Gas transportation and storage revenues increased $9.7 million due to
higher gas transportation revenues, which increased $14.9 million due to higher
volumes and rates. This increase was partly offset by decreased storage service
revenues. Revenues from the sale of by-products increased $9.7 million due
chiefly to higher sales rates.

TRANSMISSION THROUGHPUT
The changing regulatory environment has created a number of opportunities for
pipeline companies to expand and serve new markets. The Company has taken
advantage of selected market expansion opportunities, concentrating its efforts
primarily in the Northeast and along the East Coast. This expansion is supported
by the Company's network of underground storage facilities and the location and
nature of its gridlike pipeline system as a link between the country's major
longline gas pipelines and the increasing energy demands of East Coast markets.
CNG Transmission's pipeline and storage facilities will continue to enable
retail end users to take advantage of the accessibility of supplies nationwide
in the evolving

7
<PAGE> 35

deregulation of the gas industry at the retail level (see "Distribution," page
5, and "Gas and Electric Industry Developments," page 11).
Variations in weather conditions can also have a significant impact on the
throughput of the transmission operations, since a substantial portion of the
gas deliveries of these operations is ultimately used by space-heating
customers. Also, transmission operations provide transportation services to a
wide range of customers, including commercial and industrial end users, electric
power generators, and local utility companies. Therefore, the volume of gas
transported can also be affected by changes in economic and market conditions.
However, due to the straight fixed variable rate design, operating income for
the transmission operations is not significantly influenced by changes in
throughput.
Total throughput for the gas transmission operations, consisting entirely
of transportation volumes and including intercompany activity, was 732.8 Bcf,
758.4 Bcf, and 744.0 Bcf for the years 1997, 1996 and 1995, respectively.

EXPLORATION AND PRODUCTION
"Exploration and production" (E&P) includes the results of CNG Producing and the
gas and oil production activities of CNG Transmission.

E&P OPERATING INCOME BEFORE INCOME TAXES

1997
Operating income before income taxes in 1997 was $142.8 million, compared to
$133.2 million in 1996. However, the 1997 results include a non-cash charge of
$10.4 million related to the Company's impairment of Canadian oil producing
properties. In addition, workforce reduction charges totaling $.6 million are
reflected in the 1996 results. Excluding these items, 1997 operating income
would have been $153.2 million, an increase of $19.4 million compared to the
prior year. The 1997 results reflect increased gas and oil production that more
than offset the impact of lower average wellhead prices for gas and oil, higher
royalty expense, increased operating costs related to bringing certain new
production on line and increased workover activity. During 1997, the Company
added 315 Bcf of gas equivalent from additions, revisions, and purchases of gas
and oil reserves.

1996
Operating income before income taxes in 1996, excluding $.6 million of workforce
reduction charges, was $133.8 million, compared with an operating loss before
income taxes of $200.5 million in 1995. However, the 1995 results reflect a
non-cash charge of $226.2 million for the impairment of gas and oil producing
properties and workforce reduction charges totaling $7.7 million. Excluding
these special items, operating income before income taxes would have been $33.4
million for 1995. The effects of higher gas and oil wellhead prices and higher
gas and oil production contributed to the significantly improved operating
results in 1996. Higher prices and production also resulted in increased royalty
expense and higher production-related costs compared to the prior year. The
Company added 272 Bcf of gas equivalent from additions, revisions, and purchases
of gas and oil reserves in 1996.

1995
Excluding special items described above, operating results for 1995 would have
been slightly lower than the prior year. The impact of low gas wellhead prices
and lower gas and oil production slightly offset the favorable impact of higher
oil wellhead prices, a $7.5 million reduction in production-related expenses,
and reductions in overhead costs in 1995. In addition, depreciation and
amortization expense was $32.1 million lower in 1995 resulting from the
impairment of gas and oil producing properties, the effect of gas and oil
reserve additions, and lower production. Reserves equal to 210 Bcf of gas
equivalent were added in 1995.

8
<PAGE> 36

GAS AND OIL PRODUCTION AND PRICES
The following table sets forth the Company's gas and oil production and average
wellhead prices for the E&P operations for the last three years:
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
PRODUCTION 1997 1996 1995
- - -----------------------------------------------------------------------------------------
<S> <C> <C> <C>
GAS (BCF)
Nonregulated................................................ 155.3 144.5 102.6
Regulated*.................................................. 2.8 3.0 4.6
------- ------- -------
Total.................................................. 158.1 147.5 107.2
======= ======= =======
OIL (000 BBLS)
Nonregulated................................................ 7,312.0 4,765.9 3,131.7
Regulated*.................................................. -- -- 17.2
------- ------- -------
Total.................................................. 7,312.0 4,765.9 3,148.9
======= ======= =======
AVERAGE WELLHEAD PRICES
(NONREGULATED ONLY)
Gas (per Mcf)............................................... $ 2.43 $ 2.46 $ 1.89
Oil (per Bbl)............................................... $16.07 $17.60 $16.04
</TABLE>

* Cost-of-service. Hope Gas sold all of its remaining gas reserves to CNG
Producing during 1996. At December 31, 1997 and 1996, the Company's remaining
cost-of-service gas reserves were held by Peoples Natural Gas.
- - --------------------------------------------------------------------------------
The Company's average gas wellhead price was $2.43 per Mcf in 1997, down
from $2.46 in 1996. Gas production for 1997 was 158.1 Bcf, an increase of 10.6
Bcf compared to the prior year. Production from several new fields in the Gulf
of Mexico contributed to the 1997 increase. Oil wellhead prices averaged $16.07
a barrel during 1997, down $1.53 from 1996, while production increased 53%
compared to the prior year. The increase in oil production in 1997 is due
largely to the impact of Neptune, one of the Company's deep-water projects in
the Gulf of Mexico which began production in March 1997.
The Company's average gas wellhead price in 1996 was $2.46 per Mcf, up $.57
from $1.89 in 1995. Gas production in 1996 was 147.5 Bcf, up 38% from 1995. The
increase in gas production during 1996 was due partially to the impact of two
significant Gulf of Mexico projects which commenced production in the 1996 first
quarter, Popeye and Main Pass 225. Production also benefited from the effect of
production enhancement efforts at existing Company-operated fields. Average oil
wellhead prices were $17.60 per barrel in 1996, up $1.56 from 1995, while oil
production increased 51% from the prior year. The increase in oil production in
1996 was due in large part to production from the Popeye project.

E&P OPERATING REVENUES
Total operating revenues were $705.7 million in 1997, an increase of $73.4
million compared to 1996. Gas sales revenues decreased $.5 million, as increased
sales volumes were more than offset by the effect of lower average gas prices.
Revenues from oil and condensate production and brokering increased $73.0
million in 1997, with higher sales volumes more than offsetting the impact of
lower rates. Revenues from oil brokering rose $39.7 million and revenues from
oil and condensate production increased $33.3 million.
Total operating revenues increased 75% in 1996, to $632.3 million. Of the
$159.3 million increase in gas sales revenues in 1996, $90.8 million was due to
higher average gas prices and $68.5 million reflected increased volumes.
Revenues from oil and condensate production and brokering increased $108.9
million in 1996, with $77.7 million of the increase attributable to increased
volumes and the remaining increase due to higher rates. Revenues from oil
brokering increased $74.6 million while revenues from the sale of oil and
condensate production increased $34.3 million.

9
<PAGE> 37

ENERGY MARKETING SERVICES
"Energy marketing services" represents the results of CNG Energy Services
Corporation (CNG Energy Services) and CNG Power Services Corporation (CNG Power
Services). CNG Energy Services markets Company-owned gas production and arranges
gas supplies, transportation, storage and related services for large volume
customers. CNG Energy Services also holds the Company's ownership interests in
six independent power plants. CNG Power Services purchases and resells
electricity at market-based prices.
The energy marketing services component reported an operating loss before
income taxes of $17.1 million in 1997, an increased loss of $8.0 million
compared to 1996. The higher operating loss in 1997 was due chiefly to charges
recorded in connection with the establishment of reserves for pipeline
settlements and receivables. Reduced gross margins and higher overhead costs
also contributed to the 1997 operating loss. Total throughput for this component
was 856.4 Bcf in 1997, an increase of 429.3 Bcf compared to 1996. Electricity
marketed in 1997 totaled 25.2 million megawatt-hours, an increase of 20.2
million megawatt-hours over the prior year.
This component reported operating losses before income taxes of $9.1
million in 1996 and $5.7 million in 1995. The 1996 and 1995 results include
workforce reduction charges totaling $.3 million and $.5 million, respectively.
In addition to higher overhead costs, the 1996 loss occurred in part because
this component contracted for quantities of natural gas to supply power plants
during the summer air-conditioning season; these quantities proved to be too
high when third quarter 1996 weather turned cooler than expected. Reduced
transaction volumes during 1996 also adversely impacted 1996 operating results.
Total throughput for this component was 427.1 Bcf in 1996 compared to 570.8 Bcf
in 1995. Power marketing, which includes the sale of wholesale electricity,
increased to 5.0 million megawatt-hours in 1996 compared to 1.9 million
megawatt-hours in 1995.
In addition to depressed gas margins throughout the year, 1995 operating
results also reflected a $5.3 million pretax charge recognized by CNG Energy
Services in December 1995 in connection with a mark-to-market valuation of
exchange-traded futures contracts used to manage price risk exposure related to
its stored gas inventories.
Income recognized in connection with CNG Energy Services investments in
1997, 1996 and 1995 totaled $8.2 million, $5.8 million and $3.9 million,
respectively. In addition, this component recorded a charge of $7.0 million in
the fourth quarter of 1997 in connection with the decision to sell and write
down the carrying value of its interests in four independent power projects.
These amounts are not included in operating income or loss before income taxes
but are reflected in "Other income" for the component.

OTHER
"Other" in the operating income table on page 5 represents the results of
Consolidated System LNG Company (Consolidated LNG), CNG Research Company (CNG
Research) and CNG Coal Company (CNG Coal) for all three years, CNG International
Corporation (CNG International) and CNG Products and Services Corporation (CNG
Products and Services) for 1997 and 1996, and CNG Retail for 1997 only.
This segment reported an operating loss before income taxes of $9.3 million
in 1997 and $3.2 million in 1996 and operating income of $2.9 million in 1995.
Results for 1997 and 1996 reflect start-up costs incurred in connection with CNG
International, which reported pretax operating losses of $6.8 million and $3.8
million, respectively. Start-up costs of CNG Retail and CNG Products and
Services are reflected in their combined pretax operating losses of $3.8 million
and $1.5 million in 1997 and 1996, respectively. Helping to offset these
start-up costs somewhat is pretax operating income for Consolidated LNG of $1.4
million, $2.6 million and $3.7 million for the years 1997, 1996 and 1995,
respectively, reflecting the recognition of deferred income pursuant to a
regulatory order.

INTERNATIONAL ACTIVITIES
During December 1997, CNG International acquired 12.5% ownership interests in
two gas utility holding companies, Sodigas Pampeana and Sodigas Sur, and a 20%
ownership interest in an electric utility holding company, Buenos Aires Energy
Company (BAECO), from CEI Citicorp Holdings S.A. in Argentina. The gas utility
holding companies have ownership interests in two gas distribution companies,
Camuzzi Gas

10
<PAGE> 38

Pampeana and Camuzzi Gas del Sur, and BAECO has an ownership interest in an
electric distribution company, EDEA. The service territories of these companies
span from Buenos Aires province to the southernmost tip of Argentina. Camuzzi
Argentina S.A. will maintain majority ownership interests in the holding
companies. At December 31, 1997, CNG International's investments in the
Argentine holding companies totaled $79.1 million.
In December 1996, CNG International and El Paso Energy Corporation entered
into a joint venture to own and operate the Australian pipeline assets formerly
held by Tenneco Energy. CNG International owns 30% of Epic Energy Pty Ltd. (Epic
Energy), an Australian entity formed to hold the investment's operating assets.
The primary operating assets of the venture include two major long-distance
natural gas pipelines from Australia's Cooper Basin. CNG International's net
investment in Epic Energy totaled $30.9 million at December 31, 1997.

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). Reference is made to Note 4 to the consolidated financial statements,
page 30, regarding the Company's recognition under the SEC full cost rules of
impairments of its gas and oil producing properties at December 31, 1997 and
March 31, 1995.
There are a number of factors, including prices, that determine whether or
not an impairment is required. Because gas wellhead prices are subject to sudden
and seasonal fluctuations, an 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 a
price decline.

FEDERAL AND STATE REGULATORY MATTERS

GAS AND ELECTRIC INDUSTRY DEVELOPMENTS
In the current gas industry environment, competition at the retail level is
receiving increased attention by state regulators. Governments in two of the
states in which the Company operates distribution subsidiaries have enacted or
considered legislation regarding deregulation of natural gas at the retail
level. In Ohio, a 1996 law established customer choice as a state policy in the
supply of natural gas services, and allows retail customers to obtain gas from
an array of suppliers. The PUCO has proposed rules to implement the law.
Legislation is being considered in Pennsylvania that would completely unbundle
gas utility merchant functions by January 1999. One aspect of the proposal would
permit the Pennsylvania Public Utility Commission (PUC) to certify marketers, in
addition to gas utilities, as suppliers of last resort, creating competition in
a traditional gas utility function. The proposal requires the PUC to review and
act by September 1998 on plans submitted by gas utilities.
In addition to the further deregulation of the gas industry, the emerging
unbundling of services provided by electric utilities may ultimately result in
the convergence of both industries to create one overall, highly competitive
marketplace for a customer's total energy needs. During 1995 and 1996,
regulators at the federal and state levels finalized initiatives to promote
increased competition in the electric industry. These initiatives included
issuance in 1996 of FERC Order Nos. 888 and 889 (Orders 888 and 889). By
requiring open access to the national electric transmission grid, Order 888
fosters increased competition in both the generation of electricity and the
supply of bulk power to major wholesale customers. A companion order, Order 889,
addresses the timing, information access and other administrative details
associated with the FERC deregulation initiative.
Other signs of an increasingly deregulated electric utility environment
include retail competition plans adopted in several states, pilot retail
wheeling programs and pro-competition legislation proposed at both the federal
and state levels. While no legislation has been enacted in Ohio regarding
electric competition at the retail level, a legislative study committee report
issued in January 1998 calls for full customer choice by 2000. In Pennsylvania,
the Electric Generation Customer Choice and Competition Act enacted in late 1996
requires a transition to a competitive electric market at the retail level
beginning in 1999, with full competition by 2001. In February 1998, the Virginia
General Assembly passed an electric industry restruc-

11
<PAGE> 39

turing bill calling for wholesale competition beginning in 2001 and retail
competition in 2004 and sent the bill to the Virginia Senate for consideration.
In West Virginia, a bill introduced in February 1998 would authorize the Public
Service Commission (PSC) to prescribe and implement a plan to deregulate the
electric industry that must balance fairly the interests of customers, electric
utilities and the state's economy.
Reflecting the evolution to a more competitive energy environment, the pace
and size of business combinations among natural gas and electric utilities
continued to increase during 1997. These business combinations have generally
been initiated to provide benefits from economies of scale, to reduce costs by
the elimination of duplicate facilities and processes, and to improve the
strategic and competitive position of the surviving entity. Recent and pending
regulatory actions may serve to further facilitate more business combinations in
the energy industry. The FERC has streamlined its regulatory review process
regarding pending mergers. In addition, the SEC has recommended legislation to
conditionally repeal the Public Utility Holding Company Act of 1935 (PUHCA), to
which the Company is subject, in conjunction with legislation which would grant
the various state regulatory commissions greater oversight authority of
companies currently subject to the PUHCA. Legislation has been introduced which
would completely repeal the PUHCA, while another group has proposed a
comprehensive energy reform program to address market power issues, particularly
regarding the electric industry. If legislation to repeal or significantly
modify the provisions of the PUHCA becomes law, certain federal restrictions
related to diversification activities, including business combinations, for gas
and electric companies subject to the PUHCA may be eased.
Through its actions in recent years, the Company believes it is
well-positioned to compete in an evolving and increasingly deregulated energy
marketplace. The creation of CNG Retail and the ongoing development of the
energy marketing services component and participation in international
investments, coupled with streamlining and restructuring of its existing
distribution, transmission and exploration and production operations, reflects
the Company's proactive approach to meeting the demands of a more competitive
and dynamic business environment.

FEDERAL AND STATE REGULATORY ISSUES
On July 1, 1997, CNG Transmission filed a general rate filing with the FERC
requesting an annual revenue increase of $71 million, related surcharges of
approximately $12 million, and permission to establish market-based pricing for
some of its transportation and storage services. The filing seeks to accelerate
recovery of part of the Company's investment in gathering facilities which will
enable CNG Transmission to fully unbundle its gathering facilities by January 1,
2001 in accordance with prior rate case settlements. The filing reflects a
proposed rate of return on equity of 14.5%. On July 31, 1997 the FERC accepted
in part, and rejected in part, the filing. The FERC's actions included
permission to place increased rates into effect January 1, 1998, subject to
refund, the establishment of hearing procedures and rejection of the proposal to
establish market based rates.
On July 2, 1997, the PUCO approved East Ohio Gas's "Energy Choice" program
(see "Distribution," page 5).
On January 5, 1998, Hope Gas filed with the Public Service Commission of
West Virginia for a $14.5 million annual revenue increase. The rate increase
request is intended to cover improvements and extensions made to its pipeline
system. If approved, the new rates would become effective November 1, 1998.

ENVIRONMENTAL MATTERS
The Company is subject to various federal, state and local laws and regulations
relating to the protection of the environment. These laws and regulations govern
both current and future operations and potentially extend to plant sites
formerly owned or operated by the subsidiaries, or their predecessors.
Reference is made to Note 17 to the consolidated financial statements, page
43, for a detailed description of environmental matters.
Estimates of liability in the environmental area are based on current
environmental laws and regulations and existing technology. The exact nature of
environmental issues which the Company may encoun-

12
<PAGE> 40

ter in the future cannot be predicted. Additional environmental liabilities may
result in the future as more stringent environmental laws and regulations are
implemented and as the Company obtains more specific information about its
existing sites and production facilities. At present, no estimate of any such
additional liability, or range of liability amounts, can be made. However, the
amount of any such liabilities could be material.

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

FINANCIAL CONDITION

DIVIDEND AND COMMON STOCK MATTERS
In December 1997, the Board of Directors continued the quarterly dividend on the
common stock at 48.5 cents a share. Total dividends paid to common shareholders
in 1997 were $184.6 million compared with $183.0 million in 1996 and $180.8
million in 1995.
During 1997, a total of 773,283 original issue shares were issued through
various Company-sponsored plans, including 612,158 shares acquired by employees
through the exercise of outstanding stock options.
Under the Company's stock repurchase plan, authorization was granted during
1997 to increase the maximum amount of outstanding common stock that can be
repurchased from 4 million shares to 10 million shares. The shares may be
purchased in the open market from time-to-time, depending on market conditions,
or in private transactions. The Company may also acquire shares of its common
stock through certain provisions of the various stock incentive plans. 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, 1996.
The Company acquired 220,462 shares in 1997 at a cost of $12.3 million, or an
average price of $55.73 a share, primarily to fund certain non-qualified benefit
plans via a grantor trust. At December 31, 1997, a total of 659 shares were
being held as treasury stock. On January 15, 1998, the Company purchased
approximately 4.6 million shares of its common stock in a private transaction to
be used to satisfy the conversion rights of debentures called for redemption
(see "Call of Debentures," page 14).

CAPITAL SPENDING
The current capital spending program for 1998 is estimated at $714.7 million, a
17% increase compared with total capital spending in 1997. The estimated 1998
budget has been allocated as follows: distribution, $145.7 million;
transmission, $61.5 million; exploration and production, $312.7 million; energy
marketing services, $25.3 million; international, $151.6 million; and corporate
and other, $17.9 million. The increased level of capital expenditures planned
for 1998 anticipates higher spending for unregulated businesses. Exploration and
production operations reflect increased spending on deep-water projects and
increased conventional onshore and offshore drilling. Expenditures for
international operations reflect expected continued expansion of investment
opportunities in Australia and Latin America. Transmission and distribution
operations expenditures will primarily be limited to spending for enhancements
and improvements in the pipeline system and related facilities. The "corporate
and other" category includes expenditures to upgrade information systems
technology, primarily to centralize and consolidate services and financial
systems.
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. The Company may require long-term financing in 1998 to
support capital spending, and may also utilize the capital markets to take
advantage of other opportunities, including possible exploration and production
acquisitions, or to increase its financial flexibility.

13
<PAGE> 41

CAPITAL RESOURCES AND LIQUIDITY
Because of the seasonal nature of the regulated subsidiaries' heating business,
a substantial portion of the Company's cash receipts are realized in the first
half of the year. However, cash requirements for capital expenditures,
dividends, debt retirements and other working capital needs do not track this
pattern of cash receipts. Consequently, additional cash needs are satisfied
through the sale of short-term commercial paper notes or by the issuance of
long-term debt. As shown in the Consolidated Statement of Cash Flows, net cash
provided by operating activities was $742.1 million, $407.2 million and $552.7
million for the years 1997, 1996 and 1995, respectively. The increase in net
cash provided by operating activities in 1997 was due in part to higher gas
sales revenues in 1997, including the recovery of previously deferred purchased
gas costs by the distribution subsidiaries, and the payment of customer refunds
in 1996 that did not recur in 1997. The decline in net cash provided by
operating activities in 1996 was due in part to the deferral of purchased gas
costs in excess of costs currently recovered in rates and the payment of
customer refunds during the period.
In December 1997, the Company sold $300 million of 6.8% Debentures Due
December 15, 2027. The debentures are redeemable, as a whole or in part, at the
option of the Company at any time. The proceeds will be used for general
corporate purposes including capital expenditures, reduction of short-term debt,
repurchase of Company stock, and the acquisition, retirement or redemption of
debt securities.
The Company has a shelf registration with the SEC which would allow it to
sell up to an additional $700 million of debt or equity securities. The amount
and timing of any future sale of these securities will depend on capital
requirements, including financing necessary to enable the Company to pursue
asset acquisition opportunities, and financial market conditions.
The Company's embedded long-term debt cost, excluding current maturities,
at year-end 1997 was 7.20%, compared with 7.27% for 1996 and 7.69% for 1995. The
long-term debt to capitalization ratio was 39.7%, 39.3% and 38.7% at the end of
1997, 1996 and 1995, respectively. Under the provisions of one of the indentures
covering the Company's outstanding senior debenture issues, the ratio cannot
exceed 60%. The Company's senior debentures are rated A1 by Moody's Investors
Service, AA- by Standard & Poor's, AA- by Duff and Phelps, and AA by Fitch
Investors Service.
At December 31, 1997, the Company had a short-term credit agreement with a
group of banks for $775 million. The Company made no borrowings under this
agreement during 1997 and there were no amounts outstanding under any credit
agreements at December 31, 1997 or 1996. On February 13, 1998, the Company
entered into a $250 million short-term credit agreement with a bank. Borrowings
under the agreement are in the form of revolving credits which may be used for
general corporate purposes.
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 1997, of which $238.7 million was
outstanding at year-end. The Company may utilize unused portions of its credit
agreements to provide support for commercial paper notes.

CALL OF DEBENTURES
The Company's 7 1/4% Convertible Subordinated Debentures, due December 15, 2015,
were convertible into shares of the Company's common stock at an initial
conversion price of $54 per share. On January 23, 1998, the Company called for
redemption the entire principal amount outstanding totaling $246.2 million. The
redemption price was 102.18% of the principal amount plus accrued interest
payable on February 23, 1998. In anticipation of the call of this debt, on
January 15, 1998, the Company purchased approximately 4.6 million shares of its
common stock in a private transaction to satisfy the conversion obligation to
holders of the Convertible Subordinated Debentures who chose to convert. This
right to convert expired on February 13, 1998, and approximately 1.6 million of
the acquired shares were issued on conversion. The remaining acquired shares are
expected to be sold in underwritten offerings during 1998. The Company will
record an expense in the first quarter of 1998 in connection with the redemption
of the Convertible Subordinated Debentures, but such expense is not expected to
be material.

14
<PAGE> 42

YEAR 2000 TECHNOLOGY ISSUE
Similar to all business entities, the Company will be impacted by the inability
of computer application software programs to distinguish between the year 1900
and 2000 due to a commonly-used programming convention. Unless such programs are
modified or replaced prior to 2000, calculations and interpretations based on
date-based arithmetic or logical operations performed by such programs may be
incorrect.
Management is continuing to assess the Company's exposure on this issue,
including the impact on software programs and on automated process control
systems used in the operations of the Company's business. Concurrent with this
assessment, the Company is making renovations to its existing software programs
and automated process control systems to become Year 2000 compliant. While the
Company's assessment of its exposure is expected to be completed during 1998,
renovation and replacement of existing programs will continue through 1999. The
Company has budgeted approximately $10.0 million for these Year 2000 compliance
efforts.
In addition to the activities described above, the Company is currently
replacing many of its financial and operating software programs with new
programs that will be Year 2000 compliant. These new programs have significantly
reduced the costs expected to be incurred to become Year 2000 compliant.

PRICE RISK MANAGEMENT ACTIVITIES
In the normal course of business, certain of the nonregulated subsidiary
operations are subject to market risk and credit risk in connection with the
production, purchase and sale of natural gas and oil, purchase and sale of
electricity, and stored gas inventories. In addition, certain of the Company's
activities, including foreign equity investments, are subject to foreign
currency risk. Reference is made to Note 16 to the consolidated financial
statements, page 42, regarding the fair value of the Company's long-term debt
which is comprised of fixed rate instruments.

MARKET RISK
Price risk management activities expose the Company to market risk. Market risk
represents the potential loss that can be caused by the change in market value
of a particular commitment. The Company has appropriate operating procedures in
place that are administered by experienced management to help ensure that proper
internal controls are maintained. In addition, the Company has established an
independent function at the Corporate level to monitor compliance with the price
risk management policies of CNG Energy Services. These policies include
value-at-risk and notional contract and stop loss limit structures designed to
maintain exposure levels within the parameters established by management.

CREDIT RISK
Price risk management activities also expose the Company to credit risk. Credit
risk represents the potential loss that the Company would incur as a result of
nonperformance by counterparties pursuant to the terms of their contractual
obligations. The Company maintains credit policies with regards to its
counterparties that management believes minimize overall credit risk. Such
policies include the evaluation of a prospective counterparty's financial
condition, collateral requirements where deemed necessary, and the use of
standardized agreements which facilitate the netting of cash flows associated
with a single counterparty. The Company also monitors the financial condition of
existing counterparties on an ongoing basis. Considering the system of internal
controls in place and credit reserve levels at December 31, 1997, the Company
believes it is unlikely that a material adverse effect on its financial
position, results of operations or cash flows would occur as a result of
counterparty nonperformance.
Price risk management activities are conducted by two of the Company's
subsidiaries, CNG Energy Services and CNG Producing.

CNG ENERGY SERVICES
CNG Energy Services engages in wholesale energy marketing activities in the
United States and Canada. It provides energy risk management products and
services to gas and electric utilities, municipals, large industrial end users,
oil and gas producers, and other energy marketers, and to CNG Producing Company

15
<PAGE> 43

for its production and sale of natural gas. CNG Energy Services uses
over-the-counter (OTC) price swap agreements, exchange-traded futures contracts,
and option contracts to manage market risk inherent in its marketing and energy
risk management activities. The level of market risk exposure from these
activities is maintained within risk management guidelines. CNG Energy Services
also has a foreign currency swap agreement effective through April 2005 to
manage foreign exchange rate risk in connection with the payment of demand
charges for pipeline capacity in Canada.
Tables disclosing fair value and related information at December 31, 1997
for derivatives that are sensitive to changes in natural gas prices and foreign
exchange rates follow. Net notional quantities are used to calculate the
payments and quantities to be exchanged under the contractual terms of the
futures contracts and swap agreements and are not a measure of the Company's
exposure to the use of these derivatives.
It should also be noted that the tables do not include information about
CNG Energy Services' natural gas and electricity commodity purchases and sales
commitments which are sensitive to changes in natural gas and electricity
prices, and information related to firm transportation and storage agreements
for which CNG Energy Services must make specified minimum payments each month.
Therefore, the information presented regarding the use of derivatives by CNG
Energy Services does not reflect the earnings impact of the physical
transactions that may offset the financial gains and losses arising from the use
of derivatives.
The following table presents net notional quantities and weighted average
settlement prices by expected maturity date for futures contracts utilized to
manage natural gas price risk. At December 31, 1997, CNG Energy Services held no
futures contracts with maturity dates extending beyond 2000.
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
Expected Maturity Date Unrealized
------------------------ Gain (Loss)
Exchange-Traded Futures Contracts 1998 1999 2000 Total at 12/31/97
- - -------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C>
Contract volumes (in 10,000 mmbtu), purchased
(sold)............................................ (537) 144 105 (288) $(1,090)
Weighted average settlement price (per mmbtu)....... $2.30 $2.35 $2.15
- - -------------------------------------------------------------------------------------------------------
</TABLE>

The following table presents natural gas price swap information for
agreements in which the Company is obligated to pay or receive a fixed price in
exchange for receiving or paying a variable price at a location, and those in
which the Company pays or receives an amount based on prices at different
locations. At December 31, 1997, CNG Energy Services had not entered into any
price swap agreements extending beyond 2002. The weighted average variable pay
and receive forward prices are based upon quotes obtained from third party
brokers and dealers that are active in the respective markets.
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
Price Swap Agreements Expected Maturity Date
(Quantities in 10,000 mmbtu) -------------------------------------- Fair Value
(Rates per mmbtu) 1998 1999 2000 2001 2002 Total at 12/31/97
- - -----------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Pay Fixed, Receive Variable
Net notional quantities.................. 27,840 2,805 1,488 231 90 32,454 $(26,294)
Weighted average pay rate.............. $0.46 $0.55 $0.30 $1.06 $0.41
Weighted average receive rate.......... $0.36 $0.58 $0.31 $1.12 $0.47
Receive Fixed, Pay Variable
Net notional quantities.................. 25,065 3,628 759 270 29,722 $ 28,749
Weighted average pay rate.............. $0.53 $0.59 $0.43 $0.37
Weighted average receive rate.......... $0.65 $0.59 $0.43 $0.34
- - -----------------------------------------------------------------------------------------------------------
</TABLE>

16
<PAGE> 44

The following table presents notional amounts and weighted average exchange
rates, by expected maturity date, for the foreign currency swap agreement:
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
Expected Maturity Date
Foreign Currency Swap ------------------------------------------ Fair Value
Pay Fixed, Receive Variable 1998 1999 2000 2001 2002 Thereafter Total at 12/31/97
- - ----------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Notional amounts
(US$ In Thousands)...... $5,581 $6,861 $6,789 $6,611 $6,470 $18,679 $50,991 $4,528
Weighted average pay rate
(US$/Can$).............. 0.71 0.70 0.68 0.67 0.66 0.63 0.66
Weighted average receive
rate (US$/Can$)......... 0.70 0.71 0.72 0.72 0.72 0.73 0.72
- - ----------------------------------------------------------------------------------------------------------------
</TABLE>

Information regarding the fair value of OTC and exchange-traded options
contracts held by CNG Energy Services is not presented at December 31, 1997,
since the use of these derivatives was not significant.

CNG PRODUCING
CNG Producing uses price swap agreements and exchange-traded futures and options
contracts to manage commodity price risk in connection with the production and
sale of crude oil. CNG Producing's price risk management activities related to
the production and sale of natural gas are executed through intercompany
transactions with CNG Energy Services.
At December 31, 1997, CNG Producing held futures contracts covering the
sale of 1,750,000 barrels of oil with a weighted average settlement price of
$18.24 per barrel and an aggregate unrealized gain of approximately $4.4
million. All of these contracts expire during 1998. These contracts qualify and
have been designated as hedges of crude oil production, with any gains or losses
from market price changes expected to be generally offset by the earnings impact
of the related physical transaction. The fair value of options contracts and
price swap agreements held by CNG Producing at December 31, 1997 is not
presented since the use of these financial instruments was not significant.

FORWARD-LOOKING INFORMATION
Certain matters discussed in this Management's Discussion and Analysis of
Financial Condition and Results of Operations and elsewhere herein are
"forward-looking statements" intended to qualify for the safe harbors from
liability established by the Private Securities Litigation Reform Act of 1995.
These forward-looking statements can generally be identified as such because the
context of the statement will include words such as the Company "believes,"
"anticipates," "expects" or words of similar import. Similarly, statements that
describe the Company's future plans, objectives or goals are also
forward-looking statements. Such statements may address future events and
conditions concerning capital expenditures, earnings, risk management,
litigation, rate and other regulatory matters, liquidity and capital resources,
and financial accounting matters. Actual results in each instance could differ
materially from those currently anticipated in such statements, due to factors
such as: natural gas and electric industry restructuring, including ongoing
state and federal activities; the weather; demographics; general economic
conditions and specific economic conditions in the Company's distribution
service areas; developments in the legislative, regulatory and competitive
environment in which the Company operates; and other circumstances affecting
anticipated revenues and costs.

SUMMARY OF FINANCIAL DATA
The Company's Summary of Financial Data is on page 18.

17
<PAGE> 45

SELECTED FINANCIAL DATA
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
SUMMARY OF FINANCIAL DATA (THOUSAND $) 1997 1996(a) 1995(a) 1994 1993
- - -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
EARNINGS
Gas sales.............................. $4,190,158 $2,844,709 $2,595,103 $2,402,861 $2,615,036
Electricity sales, gas transportation,
storage and other.................... 1,519,862 949,600 712,222 633,167 569,049
Total operating revenues.......... 5,710,020 3,794,309 3,307,325 3,036,028 3,184,085
Purchased gas.......................... 2,960,204 1,614,983 1,590,137 1,424,020 1,594,373
Electricity, liquids and capacity
purchased............................ 869,670 346,747 153,577 107,094 79,001
Operation and maintenance.............. 798,620 789,356() 739,612() 689,575 677,666
Depreciation and amortization.......... 330,144 304,171 256,636 279,317 294,648
Impairment of gas and oil producing
properties........................... 10,351 -- 226,209 -- --
Taxes, other than income taxes......... 195,845 191,078 191,698 192,617 181,053
Operating income before
income taxes.................... 545,186 547,974 149,456 343,405 357,344
Income taxes........................... 147,053 155,830 2,943 82,427 99,906
Other income-net....................... 13,516 9,304 10,760 9,694 10,531
Write-down of coal properties.......... -- -- 31,266 -- --
Interest charges....................... 107,269 103,175 104,663 87,501 79,475
Income before change in accounting
principle............................ 304,380 298,273 21,344 183,171 188,494
Cumulative effect of applying SFAS No.
109.................................. -- -- -- -- 17,422
Net income........................ 304,380 298,273 21,344 183,171 205,916
Earnings per common share--basic(b)
Income before change in accounting
principle....................... $3.21 $3.17 $.23 $1.97 $2.03
Cumulative effect of applying SFAS
No. 109......................... -- -- -- -- .19
Net income........................ $3.21 $3.17 $.23 $1.97 $2.22
Earnings per common share--diluted(b)
Income before change in accounting
principle....................... $3.15 $3.13 $.23 $1.97 $2.02
Cumulative effect of applying SFAS
No. 109......................... -- -- -- -- .19
Net income........................ $3.15 $3.13 $.23 $1.97 $2.21
Return on average stockholders'
equity............................... 13.3% 14.0% 1.0% 8.4% 9.6%
Times fixed charges earned............. 4.59 4.76 1.21 3.53 3.95
- - -------------------------------------------------------------------------------------------------------
DIVIDENDS--CASH
Paid per common share.................. $1.94 $1.94 $1.94 $1.94 $1.92
Payout ratio...................... 60.4% 61.2% 843.5% 98.5% 86.5%
Declared per common share.............. $1.94 $1.94 $1.94 $1.94 $1.925
- - -------------------------------------------------------------------------------------------------------
ASSETS
Total assets........................... $6,313,694 $6,000,605 $5,418,293 $5,518,673 $5,437,188
Property, plant and equipment
Total investment.................. 8,714,758 8,304,205 7,929,350 7,676,956 7,346,028
Accumulated depreciation.......... 4,491,955 4,226,905 4,016,945 3,650,310 3,429,760
Capital expenditures and
acquisitions......................... 609,373 560,293 439,393 437,785 342,569
- - -------------------------------------------------------------------------------------------------------
CAPITAL STRUCTURE
Total common stockholders' equity...... $2,358,318 $2,205,152 $2,045,818 $2,184,334 $2,176,432
Long-term debt......................... 1,552,890 1,426,315 1,291,811 1,151,973 1,158,648
---------- ---------- ---------- ---------- ----------
Total capitalization.............. $3,911,208 $3,631,467 $3,337,629 $3,336,307 $3,335,080
========== ========== ========== ========== ==========
Long-term debt ratio................... 39.7% 39.3% 38.7% 34.5% 34.7%
Shares outstanding at year-end......... 95,622,622 94,933,631 93,591,623 93,027,847 92,933,828
Common stockholders' equity per
share................................ $24.66 $23.23 $21.86 $23.48 $23.42
</TABLE>

- - --------------------------------------------------------------------------------
(a) Certain amounts and ratios are not comparable with prior years due to
special charges.
(b) Prior year per share amounts have been restated in conformity with SFAS No.
128.
- - --------------------------------------------------------------------------------

18
<PAGE> 46

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Stockholders of
Consolidated Natural Gas Company

In our opinion, the consolidated financial statements appearing on pages 21
through 52 of this Appendix I to the proxy statement for the 1998 annual meeting
of stockholders present fairly, in all material respects, the financial position
of Consolidated Natural Gas Company and subsidiaries (collectively, the Company)
at December 31, 1997 and 1996, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 1997, 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.

PRICE WATERHOUSE LLP

600 Grant Street
Pittsburgh, Pennsylvania 15219-9954
February 17, 1998

19
<PAGE> 47

(THIS PAGE WAS INTENTIONALLY LEFT BLANK)

20
<PAGE> 48

CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31, 1997 1996 1995
- - ----------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
OPERATING REVENUES
Regulated gas sales..................................... $1,851,001 $1,752,223 $1,597,379
Nonregulated gas sales.................................. 2,339,157 1,092,486 997,724
---------- ---------- ----------
Total gas sales.................................... 4,190,158 2,844,709 2,595,103
Gas transportation and storage.......................... 479,505 465,110 456,370
Electricity sales....................................... 594,532 109,446 21,768
Other................................................... 445,825 375,044 234,084
---------- ---------- ----------
Total operating revenues (Note 3).................. 5,710,020 3,794,309 3,307,325
---------- ---------- ----------
OPERATING EXPENSES
Purchased gas........................................... 2,960,204 1,614,983 1,590,137
Electricity, liquids and capacity purchased............. 869,670 346,747 153,577
Operation expense (Note 5).............................. 708,012 699,289 653,731
Maintenance............................................. 90,608 90,067 85,881
Depreciation and amortization (Note 4).................. 330,144 304,171 256,636
Impairment of gas and oil producing properties (Note
4).................................................... 10,351 -- 226,209
Taxes, other than income taxes.......................... 195,845 191,078 191,698
---------- ---------- ----------
Subtotal........................................... 5,164,834 3,246,335 3,157,869
---------- ---------- ----------
Operating income before income taxes............... 545,186 547,974 149,456
Income taxes (Note 8)................................... 147,053 155,830 2,943
---------- ---------- ----------
Operating income................................... 398,133 392,144 146,513
---------- ---------- ----------
OTHER INCOME (DEDUCTIONS)
Interest revenues....................................... 2,178 2,281 9,095
Write-down of coal properties (Note 4).................. -- -- (31,266)
Other-net............................................... 11,338 7,023 1,665
---------- ---------- ----------
Total other income (deductions).................... 13,516 9,304 (20,506)
---------- ---------- ----------
Income before interest charges..................... 411,649 401,448 126,007
---------- ---------- ----------
INTEREST CHARGES
Interest on long-term debt.............................. 104,927 101,814 95,823
Other interest expense.................................. 9,116 7,224 14,732
Allowance for funds used during construction............ (6,774) (5,863) (5,892)
---------- ---------- ----------
Total interest charges............................. 107,269 103,175 104,663
---------- ---------- ----------
NET INCOME.............................................. $ 304,380 $ 298,273 $ 21,344
========== ========== ==========
Earnings per common share--basic (Note 2).......... $3.21 $3.17 $.23
Earnings per common share--diluted (Note 2)........ $3.15 $3.13 $.23
</TABLE>

- - --------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of this
statement.

21
<PAGE> 49

CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
AT DECEMBER 31, 1997 1996
- - ---------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
ASSETS

PROPERTY, PLANT AND EQUIPMENT (Note 4)
Gas utility and other plant................................. $ 5,004,139 $ 4,848,392
Accumulated depreciation and amortization................... (1,949,483) (1,840,129)
----------- -----------
Net gas utility and other plant........................ 3,054,656 3,008,263
----------- -----------
Exploration and production properties....................... 3,710,619 3,455,813
Accumulated depreciation and amortization................... (2,542,472) (2,386,776)
----------- -----------
Net exploration and production properties.............. 1,168,147 1,069,037
----------- -----------
Net property, plant and equipment...................... 4,222,803 4,077,300
----------- -----------

CURRENT ASSETS
Cash and temporary cash investments......................... 65,035 44,524
Accounts receivable
Customers................................................. 804,015 647,207
Unbilled revenues and other............................... 176,787 161,525
Allowance for doubtful accounts........................... (29,590) (15,167)
Inventories, at cost
Gas stored--current portion (Note 9)...................... 139,157 170,513
Materials and supplies (average cost method).............. 30,256 33,070
Unrecovered gas costs (Note 3).............................. 55,062 108,016
Prepayments and other current assets........................ 212,919 243,333
----------- -----------
Total current assets................................... 1,453,641 1,393,021
----------- -----------

REGULATORY AND OTHER ASSETS
Other investments........................................... 223,900 149,858
Deferred charges and other assets (Notes 3, 5, 6, 7, 8, 10
and 17)................................................... 413,350 380,426
----------- -----------
Total regulatory and other assets...................... 637,250 530,284
----------- -----------
Total assets........................................... $ 6,313,694 $ 6,000,605
=========== ===========
</TABLE>

- - --------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of this
statement.

22
<PAGE> 50

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

<TABLE>
<CAPTION>
AT DECEMBER 31, 1997 1996
- - ---------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
STOCKHOLDERS' EQUITY AND LIABILITIES
CAPITALIZATION
Common stockholders' equity (Note 11)
Common stock, par value $2.75 per share
Authorized-- 400,000,000 shares
Issued, 1997--95,623,281 shares, 1996--94,933,631
shares................................................. $ 262,964 $ 261,068
Capital in excess of par value............................ 566,755 537,002
Retained earnings (Note 13)............................... 1,539,587 1,424,624
Treasury stock, at cost (1997--659 shares)................ (38) --
Unearned compensation..................................... (10,950) (17,542)
----------- -----------
Total common stockholders' equity...................... 2,358,318 2,205,152
Long-term debt (Note 14).................................... 1,552,890 1,426,315
----------- -----------
Total capitalization................................... 3,911,208 3,631,467
----------- -----------
CURRENT LIABILITIES
Current maturities on long-term debt........................ 154,000 104,000
Commercial paper (Note 15).................................. 238,700 374,000
Accounts payable............................................ 651,365 535,296
Estimated rate contingencies and refunds (Note 3)........... 29,112 21,602
Amounts payable to customers................................ 880 --
Taxes accrued............................................... 125,056 97,336
Deferred income taxes--current (net) (Note 8)............... 13,735 36,096
Dividends declared.......................................... 46,377 46,043
Other current liabilities................................... 127,016 150,047
----------- -----------
Total current liabilities.............................. 1,386,241 1,364,420
----------- -----------
DEFERRED CREDITS
Deferred income taxes (Note 8).............................. 712,118 681,334
Accumulated deferred investment tax credits................. 26,658 28,838
Deferred credits and other liabilities (Notes 3, 6, 7 and
8)........................................................ 277,469 294,546
----------- -----------
Total deferred credits................................. 1,016,245 1,004,718
----------- -----------
COMMITMENTS AND CONTINGENCIES (Note 18)
----------- -----------
Total stockholders' equity and liabilities............. $ 6,313,694 $ 6,000,605
=========== ===========
</TABLE>

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

23
<PAGE> 51

CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31, 1997 1996 1995
- - -----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income.................................................. $ 304,380 $ 298,273 $ 21,344
Adjustments to reconcile net income to net cash provided by
operating activities
Depreciation and amortization........................... 330,144 304,171 256,636
Impairment of gas and oil producing properties.......... 10,351 -- 226,209
Write-down of coal properties........................... -- -- 31,266
Pension cost (credit)................................... (49,841) (28,604) 7,105
Stock award amortization................................ 9,620 8,436 620
Deferred income taxes-net............................... 1,881 63,230 (48,767)
Investment tax credit................................... (2,193) (2,201) (2,198)
Changes in current assets and current liabilities
Accounts receivable-net.............................. (160,887) (139,179) (116,529)
Inventories.......................................... 34,170 (55,339) 77,024
Unrecovered gas costs................................ 52,954 (82,893) (11,988)
Accounts payable..................................... 119,625 94,131 69,761
Estimated rate contingencies and refunds............. 7,510 (37,761) (24,041)
Amounts payable to customers......................... 880 (40,315) (55,825)
Taxes accrued........................................ 27,720 (16,999) 19,922
Other-net............................................ 6,984 (6,006) 13,643
Changes in other assets and other liabilities........... 48,880 48,473 84,828
Other-net............................................... (70) (252) 3,714
--------- --------- ---------
Net cash provided by operating activities............ 742,108 407,165 552,724
--------- --------- ---------
CASH FLOWS USED IN INVESTING ACTIVITIES
Plant construction and other property additions............. (520,961) (439,489) (434,739)
Proceeds from dispositions of property, plant and
equipment-net............................................. 1,056 9,079 14,066
Cost of other investments-net............................... (86,763) (87,735) (7,464)
--------- --------- ---------
Net cash used in investing activities................ (606,668) (518,145) (428,137)
--------- --------- ---------
CASH FLOWS PROVIDED BY (OR USED IN) FINANCING ACTIVITIES
Issuance of common stock.................................... 28,722 37,726 19,058
Issuance of debentures...................................... 294,945 299,567 148,899
Repayments of long-term debt................................ (119,625) (72,750) (4,000)
Commercial paper-net........................................ (134,368) 37,853 (103,399)
Dividends paid.............................................. (184,608) (183,020) (180,782)
Other-net................................................... 5 (149) (9)
--------- --------- ---------
Net cash provided by (or used in) financing
activities........................................... (114,929) 119,227 (120,233)
--------- --------- ---------
Net increase in cash and temporary cash
investments.......................................... 20,511 8,247 4,354
CASH AND TEMPORARY CASH INVESTMENTS AT JANUARY 1............ 44,524 36,277 31,923
--------- --------- ---------
CASH AND TEMPORARY CASH INVESTMENTS AT DECEMBER 31.......... $ 65,035 $ 44,524 $ 36,277
========= ========= =========
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for
Interest (net of amounts capitalized)................... $ 114,314 $ 109,602 $ 102,663
Income taxes (net of refunds)........................... $ 126,372 $ 108,742 $ 58,949
Non-cash financing activities
Issuance of common stock under benefit plans............ $ 2,742 $ 25,570 $ 1,121
Conversion of 7 1/4% Convertible Subordinated
Debentures............................................ $ 40 $ -- $ --
</TABLE>

- - --------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of this
statement.

24
<PAGE> 52

CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Methods of allocating costs to accounting periods by the subsidiaries subject to
federal or state accounting and rate regulation may differ from methods
generally applied by nonregulated companies. However, when the accounting
allocations prescribed by regulatory authorities are used for ratemaking, the
economic effects thereof determine the application of generally accepted
accounting principles. Significant accounting policies of Consolidated Natural
Gas Company (the Parent Company) and subsidiaries (collectively, the Company)
within this framework are summarized in this Note.

USE OF ESTIMATES
The consolidated financial statements reflect certain estimates and assumptions
made by management that affect the reported amounts of assets and liabilities,
the disclosure of contingent assets and liabilities at the date of the financial
statements, and the reported amounts of revenues and expenses for the periods
presented.

PRINCIPLES OF CONSOLIDATION
The Parent Company owns all of the capital stock of its subsidiaries. The
consolidated financial statements represent the accounts of the Company after
the elimination of intercompany transactions.
The Company follows the equity method of accounting for investments in
partnerships and corporate joint ventures when the Company is able to influence
the financial and operating policies of the investee. For all other investments,
the cost method is applied.

REVENUE RECOGNITION
Revenues from sales and transportation services are recognized in the same
period in which the related volumes are delivered to customers. The Company
bills and recognizes 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 to the end of the period.

UNRECOVERED GAS COSTS
Where permitted by regulatory authorities, the Company defers the difference
between the cost of gas (including certain related costs) and the amount of such
costs included in current rates. The differences are accounted for as either
unrecovered gas costs or amounts payable to customers. Unrecovered amounts are
recognized as purchased gas costs in future periods when the costs are recovered
through adjusted rates.

PRICE RISK MANAGEMENT ACTIVITIES
In the normal course of business, certain of the nonregulated subsidiaries
utilize derivative financial instruments and derivative commodity instruments to
manage exposure to price risk in connection with the production, purchase and
sale of natural gas and oil, purchase and sale of electricity, and for stored
gas inventories. Derivative financial instruments are also used to manage
foreign currency risk in connection with certain contractual commitments. The
derivatives utilized by the subsidiaries include exchange-traded futures and
options contracts, which permit settlement by physical delivery of the
commodity, and OTC commodity price swap agreements, OTC foreign currency swap
agreements and OTC options which require settlement in cash.
For derivatives that qualify (based on correlation to price movements of
gas and oil) and are designated as hedges, related gains or losses are deferred
and subsequently recognized in income, as revenues or expense, in the same
period the hedged transaction occurs. The value of derivatives that do not
qualify for hedge accounting treatment are marked-to-market each period, with
gains and losses recognized in the

25
<PAGE> 53
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

operating income of that period. The market prices used to value these
derivatives are based on closing prices quoted by an exchange and OTC quotations
when exchange quotes are not available.
Under the OTC price swap agreements, the subsidiaries make payments to, or
receive payments from, counterparties generally based on the difference between
fixed and variable gas and oil prices or on prices at different receipt points
as specified in the contracts. Under foreign currency swap agreements, payments
are made to, or received from, counterparties generally based on the difference
in the current foreign exchange rate. Settlement takes place under the swap
agreements on a monthly basis for the portion of the swap that has expired, and
amounts received or paid are recognized as an adjustment to gas and oil sales
revenues, purchased gas expense or transport capacity costs in the applicable
settlement month.
Margin accounts for open futures contracts are recorded in the Consolidated
Balance Sheet under "Prepayments and other current assets." Deferred losses or
gains are reflected in the Consolidated Balance Sheet under "Prepayments and
other current assets" and "Other current liabilities," respectively. Cash flows
from price risk management activities are reported in the Consolidated Statement
of Cash Flows as an operating activity--consistent with the category of the cash
flows from the underlying physical transaction.

PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION

GAS UTILITY AND OTHER PLANT
The property, plant and equipment accounts are stated at the cost incurred or,
where required by regulatory authorities, "original cost." Additions and
betterments are charged to the property accounts at cost. Upon normal retirement
of a plant asset, its cost is charged to accumulated depreciation together with
costs of removal less salvage. The costs of maintenance, repairs and replacing
minor items are charged principally to expense as incurred.

EXPLORATION AND PRODUCTION PROPERTIES
CNG Producing and CNG Transmission follow the full cost method of accounting for
gas and oil producing activities prescribed by the SEC. Under the full cost
method, all costs directly associated with property acquisition, exploration,
and development activities are capitalized, with the principal limitation that
such amounts not exceed the present value of estimated future net revenues to be
derived from the production of proved gas and oil reserves. If net capitalized
costs exceed the estimated value at the end of any quarterly period, then a
permanent write-down of the assets must be recognized in that period. The
limitation test is performed separately for each cost center, with cost centers
established on a country-by-country basis.
The gas producing activities of Peoples Natural Gas are subject to
cost-of-service rate regulation and are exempt from the accounting methods
prescribed by the SEC.

DEPRECIATION AND AMORTIZATION
Depreciation and amortization are recorded over the estimated service lives of
plant assets by application of the straight-line method or, in the case of gas
and oil producing properties, the unit-of-production method.
Under the full cost method of accounting, amortization is also accrued on
estimated future costs to be incurred in developing proved gas and oil reserves,
and on estimated dismantlement and abandonment costs net of projected salvage
values. However, the costs of investments in unproved properties and major
development projects are excluded from amortization until it is determined
whether or not proved reserves are attributable to such properties.

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The subsidiaries subject to cost-of-service rate regulation capitalize the
estimated costs of funds used during the construction of major projects. Under
regulatory practices, those companies are permitted to include the costs
capitalized in rate base for rate-making purposes when the completed facilities
are placed in

26
<PAGE> 54
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

service. The remaining subsidiaries capitalize interest costs as part of the
cost of acquiring certain assets. Generally, interest is capitalized on unproved
properties and major construction and development projects on which amortization
is not yet being recognized.
In determining the allowance for funds used during construction, the
following ranges of rates reflect the pretax cost of borrowed funds used to
finance construction expenditures: 1997--5 5/8% to 7 5/8%; 1996--5 1/2% to 8
1/8% and 1995--5 3/4% to 8 3/8%. Equity funds capitalized in those years were
not significant.

INCOME TAXES
The current provision for income taxes represents amounts paid or currently
payable. Investment tax credits which were required to be deferred by regulatory
authorities are being amortized as credits to income over the estimated service
lives of the related properties.

PENSION AND OTHER BENEFIT PROGRAMS

PENSION PROGRAM
The Company has qualified noncontributory defined benefit pension plans covering
substantially all employees. Benefits payable under the plans are based
primarily on each employee's years of service, age and base salary during the
five years prior to retirement. Net pension costs are determined by an
independent actuary, and the plans are funded on an annual basis to the extent
such funding is deductible under federal income tax regulations. Plan assets
consist primarily of equity securities, fixed income securities and insurance
contracts. The pension program also includes the payment of supplemental pension
benefits to certain retirees depending on retirement dates, and the payment of
benefits to certain retired executives under company-sponsored nonqualified
employee benefit plans. Certain of these nonqualified benefit plans are funded
through contributions to a grantor trust.

OTHER POSTRETIREMENT BENEFITS
In addition to pension plans, the Company sponsors defined benefit
postretirement plans covering both salaried and hourly employees and certain
dependents. The plans provide medical benefits as well as life insurance
coverage. These benefits are provided through insurance companies and other
providers with the annual cash outlays based on the claim experience of the
related plans.
Employees who retire on or after attaining age 55 and having rendered at
least 15 years of service, or employees retiring on or after attaining age 65,
are eligible to receive benefits under the plans. The plans are both
contributory and noncontributory, depending on age, retirement date, the plan
elected by the employee, and whether the employee is covered under a collective
bargaining agreement. Most of the medical plans contain cost-sharing features
such as deductibles and coinsurance. For certain of the contributory medical
plans, retiree contributions are adjusted annually.

ENVIRONMENTAL EXPENDITURES
Environmental-related expenditures associated with current operations are
generally expensed as incurred. Expenditures for the assessment and/or
remediation of environmental conditions related to past operations are charged
to expense or are deferred pending probable recovery in future rate-making
proceedings. In this connection, a liability is recognized when the assessment
or remediation effort is probable and the future costs are estimable. Estimated
future costs for the abandonment and restoration of gas and oil properties are
accrued currently through charges to depreciation.
Claims for recovery of environmental-related costs from insurance carriers
and other third parties or through regulatory procedures are recognized
separately as assets when future recovery is considered probable.

27
<PAGE> 55
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

TEMPORARY CASH INVESTMENTS
Temporary cash investments consist of short-term, highly liquid investments that
are readily convertible to cash and present no significant interest rate risk.
For purposes of the Consolidated Statement of Cash Flows, temporary cash
investments are considered to be cash equivalents.

2. EARNINGS PER SHARE

In February 1997, the FASB issued SFAS No. 128, "Earnings per Share," which
establishes new requirements for computing and presenting earnings per share.
The Company has adopted the provisions of SFAS No. 128 for the year ended
December 31, 1997, and has restated earnings per share amounts for all prior
annual and quarterly periods presented as required by the new standard. The
adoption of SFAS No. 128 did not have a material effect on the Company's
earnings per share for any of the periods presented.
A reconciliation of the income and common stock share amounts used in the
calculation of basic and diluted earnings per share (EPS) for each of the years
ended December 31, 1997, 1996 and 1995 follows (net income and share amounts in
thousands):
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
Per Share
Net Income Shares Amount
- - ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
For the year ended December 31, 1997
BASIC EPS................................................... $304,380 94,868 $3.21
======== ======= =====
Effect of dilutive securities:
Exercise of stock options.............................. 674
Vesting of performance shares.......................... 359
Conversion of 7 1/4% Convertible Subordinated
Debentures........................................... 12,128 4,559
-------- -------
DILUTED EPS................................................. $316,508 100,460 $3.15
======== ======= =====
- - ----------------------------------------------------------------------------------------------
For the year ended December 31, 1996
BASIC EPS................................................... $298,273 94,076 $3.17
======== ======= =====
Effect of dilutive securities:
Exercise of stock options.............................. 482
Vesting of performance shares.......................... 98
Conversion of 7 1/4% Convertible Subordinated
Debentures........................................... 11,823 4,559
-------- -------
DILUTED EPS................................................. $310,096 99,215 $3.13
======== ======= =====
- - ----------------------------------------------------------------------------------------------
For the year ended December 31, 1995
BASIC EPS................................................... $ 21,344 93,246 $ .23
======== ======= =====
Effect of dilutive securities:
Exercise of stock options.............................. 67
-------- -------
DILUTED EPS................................................. $ 21,344 93,313 $ .23
======== ======= =====
- - ----------------------------------------------------------------------------------------------
</TABLE>

Performance shares are considered contingent shares as defined by SFAS No.
128. Although such shares are issued and outstanding, they are excluded from the
calculation of basic earnings per share.

3. RATE MATTERS

The Company accounts for its regulated operations in accordance with SFAS No.
71, "Accounting for the Effects of Certain Types of Regulation." When the
accounting allocations prescribed by regulatory authorities are used for
ratemaking, the allocation of costs among accounting periods by the Company's
regulated

28
<PAGE> 56
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

subsidiaries resulted in the recognition of regulatory assets and liabilities at
December 31, 1997 and 1996 as follows:
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
DECEMBER 31, 1997 1996
- - -----------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C>
Regulatory assets:
Unrecovered gas costs (Note 1)......................... $ 55,062 $108,016
Order 636 transition costs (Note 3).................... 17,020 27,727
Workforce reduction costs (Note 5)..................... 8,832 11,139
Other postretirement benefits (Note 7)................. 55,070 58,966
Deferred income taxes (Note 8)......................... 103,323 101,825
Abandoned facilities (Note 10)......................... 2,271 15,791
Environmental-related expenditures (Note 17)........... 7,322 11,047
Other.................................................. 16,944 21,357
-------- --------
Total regulatory assets.......................... $265,844 $355,868
======== ========
Regulatory liabilities:
Amounts payable to customers (Note 1).................. $ 880 $ --
Estimated rate contingencies and refunds (Note 3)...... 29,112 21,602
Income taxes refundable to customers-net (Note 8)...... 55,035 57,867
-------- --------
Total regulatory liabilities..................... $ 85,027 $ 79,469
======== ========
</TABLE>

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

The Company assesses on an ongoing basis the recoverability of costs
recognized as regulatory assets and its ability to continue to apply SFAS No. 71
to its regulated operations. In the event that all or a portion of the Company's
regulated operations ceased to meet the requirements of SFAS No. 71, the Company
would be required to assess the carrying value of certain assets and liabilities
previously subject to regulation.

ESTIMATED RATE CONTINGENCIES AND REFUNDS
Certain increases in prices by the Company and other rate-making issues are
subject to final modification in regulatory proceedings. The related accumulated
provisions pertaining to these matters were $15.7 million and $6.9 million at
December 31, 1997 and 1996, including interest. These amounts are reported in
the Consolidated Balance Sheet under "Estimated rate contingencies and refunds"
together with $13.4 million and $14.7 million, respectively, which are primarily
refunds received from suppliers and refundable to customers under regulatory
procedures.

ORDER 636 TRANSITION COSTS
The distribution subsidiaries have incurred or are expected to incur obligations
to upstream pipeline companies for costs resulting from the pipeline companies'
transition to restructured services under FERC Order 636. The total estimated
liability for such costs was $17.0 million and $27.7 million at December 31,
1997 and 1996, respectively. Additional amounts may be accrued in the future if
the pipeline companies receive final FERC approval to recover such costs. Based
on management's current estimates, the distribution subsidiaries' portion of
such additional costs is not expected to be material. Due to regulatory actions
in two jurisdictions and the past rate-making treatment of similar costs in the
other jurisdictions, management believes that the distribution subsidiaries
should generally be able to pass through all Order 636 transition costs to their
customers.

29
<PAGE> 57
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION

IMPAIRMENTS OF GAS AND OIL PRODUCING PROPERTIES
As described in Note 1, certain of the subsidiaries follow the full cost method
of accounting for gas and oil producing activities as prescribed by the SEC.
Under these rules, at December 31, 1997, the Company recognized an impairment of
its Canadian oil producing properties due primarily to the decline in market
prices for heavy oil production. This non-cash charge amounted to $10.4 million
and reduced 1997 net income by $6.7 million, or $.07 per share.
The Company recognized an impairment of its United States gas and oil
producing properties at March 31, 1995, due primarily to the decline in gas
wellhead prices. The non-cash charge amounted to $226.2 million and reduced 1995
net income by $145.0 million, or $1.56 per share.

DEPRECIATION AND AMORTIZATION
Amortization of capitalized costs under the full cost method of accounting for
the Company's exploration and production operations amounted to $.88 per Mcf
equivalent of gas and oil produced in 1997, $.93 in 1996, and $.98 in 1995.
Costs of unproved properties capitalized under the full cost method of
accounting that are excluded from amortization at December 31, 1997, and the
years in which such excluded costs were incurred, follow:
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
Incurred in Years Ended December 31,
DECEMBER 31, ---------------------------------------
1997 1997 1996 1995 Prior
- - ----------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C>
Property acquisition costs.................. $48,975 $37,858 $ 5,855 $2,753 $2,509
Exploration costs........................... 41,366 29,682 3,826 4,654 3,204
Capitalized interest........................ 6,925 2,458 1,098 1,461 1,908
------- ------- ------- ------ ------
Total.................................. $97,266 $69,998 $10,779 $8,868 $7,621
======= ======= ======= ====== ======
</TABLE>

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

There are no significant properties, as defined by the SEC, excluded from
amortization at December 31, 1997. As gas and oil reserves are proved through
drilling or as properties are judged to be impaired, excluded costs and any
related reserves are transferred on an ongoing, well-by-well basis into the
amortization calculation.

WRITE-DOWN AND SUBSEQUENT SALE OF COAL PROPERTIES
In early 1995, the Company initiated an evaluation of the possible disposition
of the coal reserves and related properties owned by CNG Coal. A property
appraisal was completed by an independent geological firm, which indicated that
a write-down was warranted. Accordingly, the cost of these properties was
written down in 1995 resulting in a pretax charge amounting to $31.3 million.
This charge reduced 1995 net income by $20.3 million, or 22 cents per share, but
had no effect on the Company's cash flow. In 1996, CNG Coal completed the sale
of its coal properties to a subsidiary of Cyprus Amax Minerals Company. The
proceeds from the sale approximated the remaining book value of the properties.

5. WORKFORCE REDUCTION COSTS

During 1996, unions at two subsidiaries implemented a workforce reduction
program that consisted of a voluntary early retirement program and a voluntary
separation program. The early retirement incentives were similar to those
offered by the Company during 1995. The early retirement program was offered
from February 1 through March 31, 1996, with eligible employees retiring
effective April 1, 1996. The voluntary separation program involved severance
benefit payments to affected employees. A separate voluntary early

30
<PAGE> 58
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

retirement program for West Ohio Gas (now a division of East Ohio Gas) was
offered from October 1 through November 29, 1996, with eligible employees
retiring effective December 1, 1996. The program included early retirement
incentives similar to those offered previously at other subsidiaries.
Workforce reduction programs implemented during 1995 consisted of a
voluntary early retirement program and an involuntary separation program. The
early retirement incentives included five additional years of age and service
for determining pension benefits and were offered at seven subsidiaries during
1995. Eligible employees at each subsidiary were required to retire before
December 31, 1995. The involuntary separation program involved severance benefit
payments to affected employees.
During 1996 and 1995, a total of 119 and 571 eligible employees,
respectively, elected to accept the early retirement offer and an additional 57
and 217, respectively, were separated from the Company in conjunction with these
workforce reduction programs. In addition, during the fourth quarter of 1996 the
Company recorded a provision for severance and related benefits to be paid to
affected employees in connection with the Company's efforts to combine and
streamline certain business functions. As a result of these workforce reduction
programs, the Company recorded charges to "Operation expense" in the 1996 and
1995 Consolidated Statements of Income amounting to $15.2 million and $42.6
million, respectively. These charges reduced 1996 and 1995 net income by $9.9
million, or 10 cents per share, and $25.6 million, or 27 cents per share,
respectively. The portion of the 1996 charges recognized in the fourth quarter
amounted to $11.8 million and reduced net income for the quarter by $7.8
million, or 8 cents per share. In addition, certain of the regulated
subsidiaries have deferred, as a regulatory asset, a portion of their workforce
reduction costs pending recovery in future rates. The balance of these deferrals
was $8.8 million at December 31, 1997. The total workforce reduction costs
include the impact of curtailment accounting for the pension and postretirement
benefit plans. Details of the costs incurred during 1996 and 1995 are shown in
the following table.
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
1996 1995
------------------------------- -------------------------------
Amounts Amounts Total Amounts Amounts Total
Expensed Deferred Costs Expensed Deferred Costs
- - ---------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C> <C>
Pension and nonqualified
benefit plans:
Special termination
benefits.................. $ 4,436 $-- $ 4,436 $30,284 $ 6,893 $37,177
Curtailment gain-net......... (792) -- (792) (5,891) (277) (6,168)
Postretirement benefit plans:
Special termination
benefits.................. -- -- -- 1,086 62 1,148
Curtailment loss-net......... 1,292 -- 1,292 6,008 9,656 15,664
Severance and other............... 10,259 91 10,350 11,068 45 11,113
------- --- ------- ------- ------- -------
Total........................ $15,195 $91 $15,286 $42,555 $16,379 $58,934
======= === ======= ======= ======= =======
- - ---------------------------------------------------------------------------------------------------------
</TABLE>

31
<PAGE> 59
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. PENSION COSTS

Net pension cost, as determined by an independent actuary, included the
following components:
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, 1997 1996 1995
- - --------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Service cost--benefits earned during the period.......... $ 21,374 $ 23,741 $ 23,741
Interest cost on projected benefit obligation............ 68,635 67,426 62,125
Return on plan assets.................................... (330,296) (205,481) (265,460)
Net amortization and deferral............................ 194,419 86,522 162,002
Curtailment and special termination benefits............. -- 3,644 24,393
Special voluntary retirement programs.................... 800 800 800
--------- --------- ---------
Net pension cost (or credit)........................ $ (45,068) $ (23,348) $ 7,601
========= ========= =========
</TABLE>

- - --------------------------------------------------------------------------------
The following table sets forth the funded status of the plans, as
determined by an independent actuary, at December 31, 1997 and 1996:
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
Plans Where Assets Plans Where
Exceed Accumulated Accumulated Benefits
Benefits Exceed Assets
------------------------------------- -------------------------------------
DECEMBER 31, 1997 1996 1997 1996
- - ---------------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C>
Actuarial present value of:
Vested benefit obligation.............. $ 755,169 $ 708,224 $ 22,368 $ 22,111
========== ========== ======== ========
Accumulated benefit obligation......... $ 788,265 $ 737,868 $ 27,607 $ 26,627
========== ========== ======== ========
Projected benefit obligation........... $1,005,439 $ 927,531 $ 32,289 $ 32,420
Plan assets at fair value................... 1,804,852 1,539,039 -- --
---------- ---------- -------- --------
Plan assets in excess of (or less than)
projected benefit obligation........ 799,413 611,508 (32,289) (32,420)
Unrecognized net gain....................... (648,048) (501,869) (1,692) (2,076)
Unrecognized net obligation (or asset)...... (58,660) (67,980) 18,423 19,864
Unrecognized prior service cost............. 4,822 5,227 898 1,617
Recognition of minimum liability............ -- -- (12,947) (13,612)
---------- ---------- -------- --------
Prepaid pension cost (or pension
liability).......................... $ 97,527 $ 46,886 $(27,607) $(26,627)
========== ========== ======== ========
- - ---------------------------------------------------------------------------------------------------------------------------
</TABLE>

The projected benefit obligation at December 31, 1997 and 1996, was
determined using an annual discount rate of 7.0% and 7.5%, respectively, and an
average assumed annual rate of salary increase of 5.5%. The expected long-term
rate of return on plan assets was 9.0% per year at December 31, 1997 and 1996.
The minimum liability recognized relating to both the Company's
nonqualified employee benefit and supplemental pension plans was $12.9 million
and $13.6 million at December 31, 1997 and 1996. The related intangible asset
recognized as of those dates amounted to $10.3 million and $11.5 million,
respectively. These amounts are included in the Consolidated Balance Sheet under
"Deferred credits and other liabilities" and "Deferred charges and other
assets." Adjustments of the minimum liability and intangible asset due to
changes in assumptions or the financial status of the plans resulted in a charge
to retained earnings of $.3 million at December 31, 1997, and a credit to
retained earnings of $.1 million at December 31, 1996.

32
<PAGE> 60
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. OTHER POSTRETIREMENT BENEFITS

Net periodic postretirement benefit cost, as determined by an independent
actuary, included the following components:
- - --------------------------------------------------------------------------------

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, 1997 and 1996:
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
DECEMBER 31, 1997 1996
- - ---------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C>
Accumulated postretirement benefit obligation:
Retirees............................................... $ 279,555 $ 280,593
Fully eligible active plan participants................ 7,615 16,882
Other active plan participants......................... 71,578 80,960
--------- ---------
Total accumulated postretirement benefit
obligation...................................... 358,748 378,435
Plan assets at fair value................................... 79,740 53,153
--------- ---------
Accumulated postretirement benefit obligation in excess
of plan assets....................................... (279,008) (325,282)
Unrecognized prior service cost............................. (6,178) (6,591)
Unrecognized net loss....................................... 24,253 54,088
Unrecognized transition obligation.......................... 170,102 188,248
--------- ---------
Accrued postretirement benefit liability............... $ (90,831) $ (89,537)
========= =========
- - ---------------------------------------------------------------------------------------------------
</TABLE>

The Company is amortizing the accumulated postretirement benefit obligation
that existed at January 1, 1993 (transition obligation) over a 20-year period.
The weighted average discount rate used in determining the accumulated
postretirement benefit obligation at December 31, 1997 and 1996, was 7.0% and
7.5%, respectively. The average assumed annual rate of salary increase for the
applicable life insurance plans was 5.5% for both 1997 and 1996.
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation for the medical plans is 6.5% for 1998,
declining gradually to 4.5% 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, 1997, would
be increased by $30.9 million. A 1% change would also increase the aggregate of
the service and interest cost components of net periodic postretirement benefit
cost for 1997 by $4.5 million.
The majority of the estimated postretirement benefit costs and the
transition obligation is attributable to the rate-regulated subsidiaries.
Pending the expected recovery of SFAS No. 106 costs and related deferrals in
regulatory proceedings, these subsidiaries have deferred the differences between
SFAS No. 106 costs and amounts included in rates. The rate-regulated
subsidiaries have obtained approval for recovery in rates from

33
<PAGE> 61
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

their respective regulatory commissions for the increased level of expense
resulting from SFAS No. 106. The amount of SFAS No. 106 costs deferred at
December 31, 1997 and 1996, was $55.1 million and $59.0 million, respectively,
which is included in the Consolidated Balance Sheet under "Deferred charges and
other assets."
The FERC and certain state regulatory authorities have indicated that when
SFAS No. 106 costs are recovered in rates, amounts collected must be deposited
in irrevocable trust funds dedicated for the sole purpose of paying
postretirement benefits. Accordingly, four subsidiaries fund postretirement
benefit costs via voluntary employees' beneficiary associations (VEBAs). The
remaining subsidiaries do not prefund postretirement benefit costs, but rather
pay claims as presented. Assets held by the VEBAs consist primarily of
short-term fixed income securities.

8. INCOME TAXES

"Income taxes" in the Consolidated Statement of Income include the following:
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, 1997 1996 1995
- - --------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Current provision
Federal................................................... $128,825 $ 80,962 $ 44,705
State..................................................... 18,540 13,839 9,203
Deferred income taxes-net
Federal................................................... 2,806 60,758 (47,146)
State..................................................... (925) 2,472 (1,621)
Investment tax credit....................................... (2,193) (2,201) (2,198)
-------- -------- --------
Total..................................................... $147,053 $155,830 $ 2,943
======== ======== ========
- - --------------------------------------------------------------------------------------------
</TABLE>

Income taxes differed from the amounts shown in the next table that were
computed by applying the statutory federal income tax rate of 35% to reported
income before taxes. The reasons for the differences follow:
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, 1997 1996 1995
- - -------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Income before taxes...................................... $451,433 $454,103 $ 24,287
======== ======== ========
Computed "expected" tax expense.......................... $158,002 $158,936 $ 8,500
Increases (or reductions) in tax resulting from:
Production tax credit............................... (10,359) (9,344) (8,472)
Investment tax credit............................... (2,193) (2,201) (2,198)
State income taxes.................................. 11,450 10,602 4,928
Miscellaneous....................................... (9,847) (2,163) 185
-------- -------- --------
Total income taxes............................ $147,053 $155,830 $ 2,943
======== ======== ========
Effective tax rate.................................. 32.6% 34.3% 12.1%
- - -------------------------------------------------------------------------------------------
</TABLE>

The current and noncurrent deferred income taxes reported in the
Consolidated Balance Sheet at December 31, 1997 and 1996 represent the net
expected future tax consequences attributable to

34
<PAGE> 62
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

temporary differences between the carrying amounts of nontax assets and
liabilities and their tax bases. These temporary differences and the related tax
effect were as follows:
- - --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
1997 1996
------------------------------ ------------------------------
Deferred Deferred income Deferred Deferred income
December 31, income taxes taxes-current income taxes taxes-current
<S> <C> <C> <C> <C>
- - -----------------------------------------------------------------------------------------------------------

<CAPTION>
(In Thousands)
<S> <C> <C> <C> <C>
Deferred tax liabilities:
Excess of tax over book
depreciation...................... $537,684 $ -- $516,241 $ --
Exploration and intangible well
drilling costs.................... 225,111 -- 215,415 --
Unrecovered gas costs................ -- 19,424 -- 38,863
Other................................ 78,603 -- 76,906 --
-------- ------- -------- -------
Total liabilities.............. 841,398 19,424 808,562 38,863
-------- ------- -------- -------
Deferred tax assets:
Tax basis step-up in connection with
acquisition of subsidiary......... 18,619 -- 19,170 --
Deferred investment tax credits...... 15,854 -- 17,114 --
Overheads capitalized for tax
purposes.......................... 8,226 -- 13,747 --
Supplier and other refunds........... -- 187 -- 277
Other................................ 86,581 5,502 77,197 2,490
Valuation allowance.................. -- -- -- --
-------- ------- -------- -------
Total assets................... 129,280 5,689 127,228 2,767
-------- ------- -------- -------
Total deferred income taxes.... $712,118 $13,735 $681,334 $36,096
======== ======= ======== =======
- - -----------------------------------------------------------------------------------------------------------
</TABLE>

A regulatory liability amounting to $55.0 million has been recorded at
December 31, 1997 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 $103.3 million has been recorded at December 31, 1997. These
amounts are included in the Consolidated Balance Sheet under "Deferred credits
and other liabilities" and "Deferred charges and other assets," respectively.

9. GAS STORED

The distribution subsidiaries, except Virginia Natural Gas, value their stored
gas inventory under the LIFO method. Based upon the average price of gas
purchased during 1997, the current cost of replacing the inventory of "Gas
stored--current portion" exceeded the amount stated on a LIFO basis by
approximately $200.5 million at December 31, 1997. Virginia Natural Gas and CNG
Energy Services value their stored gas inventory under the weighted average cost
method.
A portion of gas in underground storage used as a pressure base and for
operational balancing is included in "Property, Plant and Equipment" in the
amount of $126.4 million at December 31, 1997 and 1996.

10. UNAMORTIZED ABANDONED FACILITIES

In 1988, Consolidated LNG received FERC approval for the abandonment of its
interest in liquefied natural gas facilities at Cove Point, Maryland. In
connection with the abandonment, Consolidated LNG recorded a deferred asset in
accordance with the provisions of SFAS No. 90, "Accounting for Abandonments and

35
<PAGE> 63
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Disallowances of Plant Costs." This deferred asset, which represents the present
value of allowable costs expected to be recovered, has been amortized over a
10-year recovery period which will end February 28, 1998, as prescribed in the
FERC order.

11. COMMON STOCKHOLDERS' EQUITY

A summary of the changes in stockholders' equity follows:
- - --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Common Stock Capital in Excess
Issued of Par Value
--------------------- -----------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Number Value Retained Unearned
of Shares at Par Paid-In Other Total Earnings Compensation
- - ----------------------------------------------------------------------------------------------------------------

<CAPTION>
(In Thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at December 31,
1994....................... 93,028 $255,827 $418,348 $40,280 $458,628 $1,469,879 $ --
Net income................... -- -- -- -- -- 21,344 --
Cash dividends declared
Common stock ($1.94 per
share)................... -- -- -- -- -- (181,055) --
Common stock issued
Stock options.............. 217 596 7,453 -- 7,453 -- --
System Thrift Plans........ 213 586 7,586 -- 7,586 -- --
DRP*....................... 104 287 3,837 -- 3,837 -- --
Stock awards-net........... 30 81 1,040 -- 1,040 -- --
Purchase of treasury stock... -- -- -- -- -- -- --
Sale of treasury stock....... -- -- (9) -- (9) -- --
Pension liability
adjustment................. -- -- -- -- -- (262) --
------ -------- -------- ------- -------- ---------- --------
Balance at December 31,
1995....................... 93,592 257,377 438,255 40,280 478,535 1,309,906 --
Net income................... -- -- -- -- -- 298,273 --
Cash dividends declared
Common stock ($1.94 per
share)................... -- -- -- -- -- (183,671) --
Common stock issued
Stock options.............. 769 2,113 29,662 -- 29,662 -- --
Performance shares-net..... 378 1,040 16,336 -- 16,336 -- (17,376)
Stock awards-net........... 98 270 4,404 -- 4,404 -- (4,560)
DRP*....................... 97 268 4,688 -- 4,688 -- --
Amortization and
adjustment............... -- -- 3,520 -- 3,520 -- 4,394
Purchase of treasury stock... -- -- -- -- -- -- --
Sale of treasury stock and
other...................... -- -- (143) -- (143) -- --
Pension liability adjustment
(Note 6)................... -- -- -- -- -- 116 --
------ -------- -------- ------- -------- ---------- --------
Balance at December 31,
1996....................... 94,934 261,068 496,722 40,280 537,002 1,424,624 (17,542)
Net income................... -- -- -- -- -- 304,380 --
Cash dividends declared
Common stock ($1.94 per
share)................... -- -- -- -- -- (184,942) --
Common stock issued
Stock options.............. 612 1,683 23,615 -- 23,615 -- --
DRP*....................... 62 171 3,244 -- 3,244 -- --
Stock awards-net........... 25 69 1,318 -- 1,318 -- (1,350)
Conversion of debentures... 1 2 38 -- 38 -- --
Performance shares-net..... (11) (29) (106) -- (106) -- 135
Amortization and
adjustment............... -- -- 1,490 -- 1,490 -- 7,807
Purchase of treasury stock... -- -- -- -- -- -- --
Sale of treasury stock and
other...................... -- -- 154 -- 154 -- --
Pension liability adjustment
(Note 6)................... -- -- -- -- -- (309) --
Cumulative translation
adjustment................. -- -- -- -- -- (4,166) --
------ -------- -------- ------- -------- ---------- --------
Balance at December 31,
1997....................... 95,623 $262,964 $526,475 $40,280 $566,755 $1,539,587 $(10,950)
====== ======== ======== ======= ======== ========== ========

<CAPTION>
Treasury Stock
----------------------
Number
of Shares Cost
- - -------------------------------------------------------------

<S> <C> <C>
Balance at December 31,
1994....................... -- $ --
Net income................... -- --
Cash dividends declared
Common stock ($1.94 per
share)................... -- --
Common stock issued
Stock options.............. -- --
System Thrift Plans........ -- --
DRP*....................... -- --
Stock awards-net........... -- --
Purchase of treasury stock... (17) (634)
Sale of treasury stock....... 17 634
Pension liability
adjustment................. -- --
---- --------
Balance at December 31,
1995....................... -- --
Net income................... -- --
Cash dividends declared
Common stock ($1.94 per
share)................... -- --
Common stock issued
Stock options.............. -- --
Performance shares-net..... -- --
Stock awards-net........... -- --
DRP*....................... -- --
Amortization and
adjustment............... -- --
Purchase of treasury stock... (147) (8,144)
Sale of treasury stock and
other...................... 147 8,144
Pension liability adjustment
(Note 6)................... -- --
---- --------
Balance at December 31,
1996....................... -- --
Net income................... -- --
Cash dividends declared
Common stock ($1.94 per
share)................... -- --
Common stock issued
Stock options.............. -- --
DRP*....................... -- --
Stock awards-net........... -- --
Conversion of debentures... -- --
Performance shares-net..... -- --
Amortization and
adjustment............... -- --
Purchase of treasury stock... (220) (12,286)
Sale of treasury stock and
other...................... 219 12,248
Pension liability adjustment
(Note 6)................... -- --
Cumulative translation
adjustment................. -- --
---- --------
Balance at December 31,
1997....................... (1) $ (38)
==== ========
</TABLE>

- - --------------------------------------------------------------------------------
* Dividend Reinvestment Plan.

36
<PAGE> 64
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

SHAREHOLDER RIGHTS PLAN
During 1995, the Board of Directors adopted a shareholder rights plan and on
January 23, 1996, declared a dividend of one right (Right) for each share of
common stock outstanding at the close of business on February 28, 1996. Each
Right would entitle the holder to purchase from the Company one-half of one
share of common stock at a price of $175 per share ($87.50 per half-share),
subject to adjustment (Purchase Price), if certain conditions are met in
connection with a possible acquisition of the common stock of the Company by a
third party. If the Rights become exercisable, each holder may exercise a Right
and receive common stock (or, in certain cases, cash, property or other
securities) of the Company or common stock of the acquiring company having a
value equal to twice the Right's then current Purchase Price.
Also, under certain conditions, the Board of Directors may exchange the
Rights, in whole or in part, at an exchange ratio of one share of common stock
(and/or other securities, cash or other assets having the same value as a share
of common stock) per Right, subject to adjustment, or may redeem the Rights in
whole at a price of $0.01 per Right. Until a Right is exercised or exchanged for
common stock, the holder, as such, is not a stockholder of the Company. Unless
earlier exercised or redeemed, the Rights will expire on February 28, 2006.

UNISSUED SHARES
At December 31, 1997, 304,376,719 shares of common stock were unissued. Shares
have been registered with the SEC for possible issuance under various benefit
plans. Shares acquired by these plans can consist of original issue shares,
treasury shares or shares purchased in the open market. Shares have also been
registered with the SEC for possible issuance to shareholders under the Dividend
Reinvestment Plan and for issuance upon conversion of the Company's convertible
subordinated debentures. In addition, the Company has a shelf registration with
the SEC which would allow it to sell up to an additional $700 million of debt or
equity securities at December 31, 1997.

TREASURY STOCK
Under a stock repurchase plan approved by the Board of Directors, the Company
can purchase in the open market up to 10,000,000 shares of its common stock. The
Company may also acquire shares of its common stock through certain provisions
of the Company's various stock incentive plans. Shares repurchased or acquired
are held as treasury stock and are available for reissuance for general
corporate purposes or in connection with various employee benefit plans. When
treasury shares are reissued, the difference between the market value at
reissuance and the cost of shares is reflected in "Capital in excess of par
value." The cost of any shares held as treasury stock is shown as a reduction in
common stockholders' equity in the Consolidated Balance Sheet. No treasury
shares were held at December 31, 1996. At December 31, 1997, a total of 659
shares were being held as treasury stock.

PRE-1997 STOCK AWARD AND OPTION PLANS
Prior to 1997, stock awards, stock options and other stock-based awards were
granted to employees under the Long-Term Incentive Plan, the 1991 Stock
Incentive Plan (1991 Plan) and the 1995 Employee Stock Incentive Plan (1995
Plan). The Long-Term Incentive Plan terminated by its terms on November 9, 1991.
In addition, there were no shares authorized for issuance under either the 1991
Plan or the 1995 Plan at December 31, 1997. However, the provisions of these
plans continue with respect to stock awards granted whose restrictions have not
yet lapsed and stock options granted which have not been exercised at December
31, 1997.

1997 STOCK INCENTIVE PLAN
The 1997 Stock Incentive Plan (1997 Plan) provides for the granting of stock
awards, stock options and other stock-based awards to employees and Directors of
the Company effective January 1, 1997, including

37
<PAGE> 65
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

grants made on or after that date pursuant to the Long-Term Strategic Incentive
Program described below. The maximum number of shares authorized for issuance in
each calendar year is determined in accordance with a formula contained in the
1997 Plan. At December 31, 1997, 5,832,110 shares were available for issuance
under the 1997 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. These options, other than tri-annual options granted under the
Long-Term Strategic Incentive Program, generally are exercisable in four equal
annual installments commencing with the second anniversary of the grant and
expire after ten years from the date of grant.
Stock appreciation rights may also be granted, either alone or in tandem
with stock options. These rights permit the recipient to receive, upon exercise,
the excess of the fair market value of a share on the date of exercise over the
grant price. The grant price is generally the fair market value of the stock on
the date of grant. As of December 31, 1997, no stock appreciation rights have
been granted under the plan.
The granting of stock awards constitutes a non-cash financing activity of
the Company.

LONG-TERM STRATEGIC INCENTIVE PROGRAM
Grants under the Long-Term Strategic Incentive Program, consisting of
performance restricted stock awards (performance shares) and stock options, are
expected to be made every three years, with the first such grants made on
January 2, 1996.
Performance shares will vest contingent upon attainment of certain
strategic business results over a three-year period. The market value of the
performance shares on the grant date, as adjusted quarterly for changes in the
current market price of the Company's common stock, is recorded as compensation
expense over the three-year vesting period.
Stock options granted under this program (tri-annual options) vest after
three years and will be exercisable from the vesting date until ten years from
the grant date if certain strategic business results are attained during the
vesting period. However, the exercise period will be reduced to one day for all
or a portion of the options granted if such results are not achieved. As the
number of options are known and the option price equals the market price at the
grant date, no compensation expense is recognized for these options under
generally accepted accounting principles.

ACCOUNTING FOR STOCK AWARDS AND STOCK OPTIONS
As allowed by SFAS No. 123, "Accounting for Stock-Based Compensation," the
Company continues to follow Accounting Principles Board Opinion No. 25 and
related interpretations (APB No. 25), for accounting for stock-based
compensation. The Company granted stock awards totaling 43,000 shares in 1997,
103,000 shares in 1996, and 34,000 shares in 1995 with weighted average market
prices per share on award dates of $51.89, $47.43, and $39.15, respectively. In
addition, performance shares totaling 55,000 shares in 1997 and 404,000 shares
in 1996 were issued at a weighted average market price of $53.02 and $45.87 per
share, respectively. The Company recorded compensation expense of $9.7 million,
$8.7 million and $.8 million for the years ended December 31, 1997, 1996 and
1995, respectively, in connection with its performance shares, restricted stock
and other stock compensation awards. In accordance with APB No. 25, no
compensation expense has been recognized for the Company's stock options.

38
<PAGE> 66
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

A summary of the Company's stock option activity under the plans described
above for the years ended December 31, 1995 through 1997, follows:
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
Weighted Average
Number Option Price
of Shares Per Share
- - -----------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C>
Shares under option:
At January 1, 1995..................................... 2,557 $42.43
Granted................................................ 1,078 $37.32
Exercised.............................................. (217) $35.88
Cancelled.............................................. (470) $41.14
-----
At December 31, 1995................................... 2,948 $41.25
Granted(1)............................................. 3,534 $45.53
Exercised.............................................. (769) $41.37
Cancelled(1)........................................... (196) $43.13
-----
At December 31, 1996................................... 5,517 $43.90
Granted(2)............................................. 885 $54.09
Exercised.............................................. (612) $41.33
Cancelled(2)........................................... (583) $45.74
-----
At December 31, 1997................................... 5,207 $45.73
=====
</TABLE>

(1) Includes 3,006,000 tri-annual options granted and 65,000 tri-annual options
cancelled.

(2) Includes 332,084 tri-annual options granted and 367,883 tri-annual options
cancelled.

Options were exercisable for the purchase of 599,534 shares, 673,305 shares, and
1,048,064 shares at December 31, 1997, 1996 and 1995, respectively. Effective
January 2, 1998, additional options for the purchase of 529,500 shares were
granted to eligible employees.
- - --------------------------------------------------------------------------------

The following table summarizes information about stock options outstanding
at December 31, 1997.
- - --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
--------------------------------------------------- --------------------------------
<S> <C> <C> <C> <C> <C>
Weighted Average Weighted Weighted
Number Remaining Average Number Average
Range of Exercise Prices Outstanding Contractual Life Exercise Price Exercisable Exercise Price
- - --------------------------------------------------------------------------------------------------------------------

<CAPTION>
(In Thousands) (In Thousands)
<S> <C> <C> <C> <C> <C>
$34.75--$40.00 712 6.33 YRS. $37.12 205 $36.59
$40.01--$50.00 3,369 7.42 YRS. $44.92 310 $44.95
$50.01--$59.94 1,126 8.35 YRS. $54.01 85 $50.77
- - --------------------------------------------------------------------------------------------------------------------
</TABLE>

39
<PAGE> 67
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table presents the weighted-average fair value of stock
options granted during 1995 through 1997 and the weighted-average assumptions
used to compute fair values under the Black-Scholes option-pricing model:
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, 1997 1996 1995
- - ----------------------------------------------------------------------------------------
<S> <C> <C> <C>
Option fair value........................................... $8.96 $5.84 $5.50
Assumptions
Dividend yield......................................... 3.6% 4.3% 5.0%
Expected volatility.................................... 16.8% 17.5% 19.2%
Risk-free interest rate................................ 6.4% 5.4% 6.9%
Expected option life (years)........................... 4.8 4.9 4.9
- - ----------------------------------------------------------------------------------------
</TABLE>

If compensation expense for stock options granted during 1995 through 1997
had been determined based on the fair value at the grant dates for such awards
in accordance with SFAS No. 123, the effect on the Company's net income and
earnings per share for each of the years would have been as follows:
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, 1997 1996 1995
- - ----------------------------------------------------------------------------------------
<S> <C> <C> <C>
NET INCOME (In Millions):
As reported............................................ $304.4 $298.3 $ 21.3
Pro forma.............................................. $298.8 $294.1 $ 20.7
BASIC EPS:
As reported............................................ $ 3.21 $ 3.17 $ .23
Pro forma.............................................. $ 3.15 $ 3.13 $ .22
DILUTED EPS:
As reported............................................ $ 3.15 $ 3.13 $ .23
Pro forma.............................................. $ 3.10 $ 3.08 $ .22
- - ----------------------------------------------------------------------------------------
</TABLE>

12. PREFERRED STOCK

The Company's authorized preferred stock consists of 5,000,000 shares at a par
value of $100 each. There were no shares of preferred stock issued or
outstanding at December 31, 1997 or 1996.

13. DIVIDEND RESTRICTIONS

One of the Company's indentures relating to senior debenture issues contains
restrictions on dividend payments by the Company and acquisitions of its capital
stock. Under the indenture provisions, $720.4 million of consolidated retained
earnings was free from such restrictions at December 31, 1997. The indenture
also imposes dividend limitations on the subsidiaries, but at December 31, 1997,
these limitations did not restrict their ability to pay dividends to the
Company.

40
<PAGE> 68
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14. LONG-TERM DEBT

Long-term debt, excluding current maturities, follows:
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
DECEMBER 31, 1997 1996
- - --------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C>
Debentures
6.8%, Due December 15, 2027............................ $ 300,000 $ --
6 5/8%, Due December 1, 2008........................... 150,000 150,000
6 7/8%, Due October 15, 2026........................... 150,000 150,000
7 3/8%, Due April 1, 2005.............................. 150,000 150,000
6 5/8%, Due December 1, 2013........................... 150,000 150,000
5 3/4%, Due August 1, 2003............................. 150,000 150,000
5 7/8%, Due October 1, 1998............................ -- 150,000
8 3/4%, Due October 1, 2019............................ 150,000 150,000
8 3/4%, Due June 1, 1999............................... 100,000 100,000
8 5/8%, Due December 1, 2011........................... 15,625 31,250
Unamortized debt discount, less premium................ (11,319) (7,429)
Convertible Subordinated Debentures
7 1/4%, Due December 15, 2015.......................... 246,165 246,205
Unamortized debt discount.............................. (1,581) (1,711)
9.94% Unsecured loan due January 1, 1999.................... 4,000 8,000
---------- ----------
Total.................................................. $1,552,890 $1,426,315
========== ==========
- - --------------------------------------------------------------------------------------
</TABLE>

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 amount to "Interest on long-term debt" over the life of each
debenture issue.
The Company's 7 1/4% Convertible Subordinated Debentures, due December 15,
2015, were convertible into shares of the Company's common stock at an initial
conversion price of $54 per share. On January 23, 1998, the Company called for
redemption the entire principal amount outstanding totaling $246.2 million. The
redemption price was 102.18% of the principal amount plus accrued interest
payable on February 23, 1998. In anticipation of the call of this debt, on
January 15, 1998, the Company purchased approximately 4.6 million shares of its
common stock in a private transaction to satisfy the conversion obligation to
holders of the Convertible Subordinated Debentures who chose to convert. The
right to convert expired on February 13, 1998, and approximately 1.6 million of
the acquired shares were issued on conversion. The remaining acquired shares are
expected to be sold in underwritten offerings during 1998.
In late 1996, the Company called for redemption $53.1 million principal
amount of the 8 5/8% Debentures Due December 1, 2011. In connection with the
call, the Company placed funds into an irrevocable trust in December 1996 for
the sole purpose of paying the principal amount and related call premium and
accrued interest. As such, the debt was removed from the Consolidated Balance
Sheet at December 31, 1996. Payment was made from the trust on February 1, 1997.
This transaction resulted in a 1996 charge to "Other Income" of $5.0 million.
The aggregate principal amounts of the Company's debentures maturing in the
years 1998 through 2002 are: $150.0 million; $107.1 million; $7.1 million; $7.1
million and $7.1 million.
The 9.94% unsecured loan due January 1, 1999, is an obligation of Virginia
Natural Gas. This $20.0 million loan, which is being repaid in five annual
installments of $4.0 million each beginning January 1, 1995, has been guaranteed
by the Company.

41
<PAGE> 69
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15. SHORT-TERM BORROWINGS

The weighted average interest rate on the Company's commercial paper notes
outstanding at December 31, 1997 and 1996, was 6.21% and 5.70%, respectively.
The Company has a $775.0 million credit agreement with a group of banks.
Borrowings under this 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 banks. The loans may
be borrowed, paid or repaid and reborrowed on a few days notice. Varying
interest rate options are available for syndicated loans, while the interest
rate on money market loans is determined from quotes rendered by the
participating banks. This agreement may be used for general corporate purposes,
including the support of commercial paper notes. This agreement is currently
scheduled to expire on June 26, 1998; however, the Company expects that the
agreement will be renewed or replaced by a comparable agreement. A facility fee
is charged under this agreement but is not considered significant. There were no
borrowings under this agreement at December 31, 1997.
On February 13, 1998, the Company entered into a $250.0 million short-term
credit agreement with a bank. Borrowings under the agreement are in the form of
revolving credits which may be used for general corporate purposes.

16. FINANCIAL INSTRUMENTS

FAIR VALUES
The estimated fair value of the Company's long-term debt, including current
maturities, was as follows at December 31, 1997 and 1996:
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
1997 1996
----------------------- -----------------------
Carrying Fair Carrying Fair
December 31, Amount Value Amount Value
- - ------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C>
Long-term debt........................... $1,719,790 $1,789,577 $1,539,455 $1,563,440
- - ------------------------------------------------------------------------------------------------
</TABLE>

The fair values were estimated based upon closing transactions and/or
quotations for the Company's debentures as of those dates. Temporary cash
investments and commercial paper notes are stated at amounts which approximate
fair value due to the short maturities of those financial instruments.

DERIVATIVES AND PRICE RISK MANAGEMENT ACTIVITIES

FUTURES AND OPTIONS CONTRACTS
The Company's price risk management activities include exchange-traded futures
and options contracts, which can be settled through the purchase or delivery of
commodities, and OTC options, which require settlement in cash. CNG Energy
Services uses such instruments to manage commodity price risk regarding gas and
electricity purchase and sale commitments and stored gas inventories, while CNG
Producing uses them to manage risk in connection with the production and sale of
crude oil.
At December 31, 1997, CNG Energy Services had natural gas futures contracts
related to gas purchase and sale commitments and gas storage inventory covering
2.9 Bcf of gas on a net basis maturing through 2000. Also at December 31, 1997,
CNG Producing held crude oil futures contracts maturing through 1998 covering
1,750,000 barrels of oil.
For contracts used by the Company that qualify and have been designated as
hedges, any gains or losses resulting from market price changes are expected to
be generally offset by the related physical transaction. The Company's net
unrealized gain related to futures contracts was approximately $5.1 million at
December 31, 1997.

42
<PAGE> 70
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

SWAP AGREEMENTS
In addition to futures and options contracts, CNG Energy Services and CNG
Producing enter into OTC price swap agreements to manage their exposure to
commodity price risk under existing sales commitments.
At December 31, 1997, CNG Energy Services had swap agreements of varying
duration outstanding with several counterparties to exchange monthly payments on
net notional quantities of gas over the ensuing five years. Net notional
quantities at December 31, 1997 related to those swap agreements in which CNG
Energy Services pays a fixed price in exchange for a variable price totaled
324.5 Bcf, while net notional quantities related to agreements in which CNG
Energy Services pays a variable price in exchange for a fixed price totaled
297.2 Bcf. Net notional quantities or amounts do not represent the quantities or
amounts exchanged by the parties and, thus, are not a measure of the exposure of
the Company through its use of derivatives. The amounts exchanged are calculated
on the basis of monthly notional quantities and other terms of the agreements.
The Company's net unrealized loss related to swap agreements was approximately
$4.7 million at December 31, 1997. Profits expected on anticipated sales related
to the hedged transactions should generally offset the estimated unrealized
losses on the swap agreements.
CNG Energy Services also has a foreign currency swap agreement effective
through April 2005 to manage foreign exchange rate risk in connection with the
payment of demand charges for pipeline capacity in Canada. The aggregate
notional amount underlying this swap agreement was approximately $51.0 million
at December 31, 1997. The unrealized gain related to this swap agreement was
$4.5 million at December 31, 1997.

MARKET AND CREDIT RISK
Price risk management activities expose the Company to market risk. Market risk
represents the potential loss that can be caused by the change in market value
of a particular commitment. The Company has appropriate operating procedures in
place that are administered by experienced management to help ensure that proper
internal controls are maintained. In addition, the Company has established an
independent function at the Corporate level to monitor compliance with the price
risk management policies of CNG Energy Services. These policies include
value-at-risk and notional contract and stop loss limit structures designed to
maintain exposure levels within the parameters established by management.
Price risk management activities also expose the Company to credit risk.
Credit risk represents the potential loss that the Company would incur as a
result of nonperformance by counterparties pursuant to the terms of their
contractual obligations. The Company maintains credit policies with regard to
its counterparties that management believes minimize overall credit risk. Such
policies include the evaluation of a prospective counterparty's financial
condition, collateral requirements where deemed necessary, and the use of
standardized agreements which facilitate the netting of cash flows associated
with a single counterparty. The Company also monitors the financial condition of
existing counterparties on an ongoing basis. Considering the system of internal
controls in place and credit reserve levels at December 31, 1997, the Company
believes it is unlikely that a material adverse effect on its financial
position, results of operations or cash flows would occur as a result of
counterparty nonperformance.

17. ENVIRONMENTAL MATTERS

The Company is subject to various federal, state and local laws and regulations
relating to the protection of the environment. These laws and regulations govern
both current and future operations and potentially extend to plant sites
formerly owned or operated by the subsidiaries, or their predecessors.
The Company has taken a proactive position with respect to environmental
concerns. As part of normal business operations, subsidiaries periodically
monitor their properties and facilities to identify and resolve potential
environmental matters, and the Company conducts general environmental surveys on
a continuing basis at its operating facilities to monitor compliance with
environmental laws and regulations.

43
<PAGE> 71
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As part of this process, voluntary surveys at subsidiary sites have been
conducted to determine the extent of any possible soil contamination due to
hazardous substances, such as mercury, and when contamination has been
discovered remediation efforts are undertaken. Further, on August 16, 1990, CNG
Transmission entered into a Consent Order and Agreement with the Commonwealth of
Pennsylvania Department of Environmental Resources (DER) in which CNG
Transmission has agreed with the DER's determination of certain violations of
the Pennsylvania Solid Waste Management Act, the Pennsylvania Clean Streams Law
and the rules and regulations promulgated thereunder. No civil penalties had
been assessed as of December 31, 1997. Pursuant to the Order and Agreement, CNG
Transmission continues to perform sampling, testing and analysis, and conducting
a program of remediation at some of its Pennsylvania facilities. Total
remediation costs in connection with these sites and the Order and Agreement are
not expected to be material with respect to the Company's financial position,
results of operations or cash flows. Based on current information, the Company
has recognized a gross estimated liability amounting to $10.9 million at
December 31, 1997, for future costs expected to be incurred to remediate or
mitigate hazardous substances at these sites and at facilities covered by the
Order and Agreement.
Inasmuch as certain environmental-related expenditures are expected to be
recoverable in future regulatory proceedings, a regulatory asset amounting to
$7.3 million at December 31, 1997, is included in the Consolidated Balance Sheet
under the caption "Deferred charges and other assets." Also, uncontested claims
amounting to $1.5 million at December 31, 1997, were recognized for
environmental-related costs probable for recovery through joint-interest
operating agreements.
The total amounts included in operating expenses for remediation and other
environmental-related costs, and the components of such costs, are as follows:
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, 1997 1996 1995
- - ---------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Recurring costs for ongoing operations...................... $3,430 $4,174 $3,094
Mandated remediation and other compliance costs............. 1,473 (419) 2,307
Voluntary remediation costs................................. 228 2,705 1,630
Other....................................................... 14 3 79
------ ------ ------
Total.................................................. $5,145 $6,463 $7,110
====== ====== ======
</TABLE>

- - --------------------------------------------------------------------------------
CNG Transmission and certain of the distribution subsidiaries are subject
to the Federal Clean Air Act (Clean Air Act) and the Federal Clean Air Act
Amendments of 1990 (1990 amendments) which added significantly to the existing
Clean Air Act requirements. As a result of the 1990 amendments, these
subsidiaries were required to install Reasonably Available Control Technology at
some compressor stations to reduce nitrogen oxide emissions. Compliance required
capital expenditures to similarly retrofit some of the compressor engines along
the Company's pipeline system. The Company has completed the installation of
emission control equipment and the installation and testing of compressor
engines and related equipment required by the 1990 amendments. In addition,
several of the subsidiaries are required by the Clean Air Act Amendments to
acquire Title V permits for major facilities. Progress is on schedule for these
permits, with no major expenditures anticipated. The 1990 amendments may also
require installation of Maximum Available Control Technology (MACT) to control
the emissions of certain hazardous air pollutants. The Company is participating
with industry groups and the Environmental Protection Agency (EPA) in the
development of these regulations but is unable to estimate the cost of
installing MACT, if required.
The Company expended de minimis amounts in 1997, $6.8 million in 1996 and
$11.3 million in 1995, to comply with the 1990 amendments. The total capital
expenditures required to comply with the 1990 amendments are expected to be
recoverable through future regulatory proceedings.
The Company has determined that it is associated with 16 former
manufactured gas plant sites, five of which are currently owned by
subsidiaries. Studies conducted by other utilities at their former

44
<PAGE> 72
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

manufactured gas plants have indicated that their sites contain coal tar and
other potentially harmful materials. None of the 16 former sites with which the
Company is associated is under investigation by any state or federal
environmental agency, and no investigation or action is currently anticipated.
At this time it is not known if, or to what degree, these sites may contain
environmental contamination. Therefore, the Company is not able to estimate the
cost, if any, that may be required for the possible remediation of these sites.
The Company discovered in the course of conducting a routine environmental
survey at East Ohio Gas that some of its practices for collecting and handling
pipeline fluids that may have been contaminated with polychlorinated biphenyls
(PCBs) may not have complied with environmental regulations. The appropriate
agencies have been notified as part of the federal self-disclosure process and
discussions are continuing with the agencies to gain approval of revised
collection and handling procedures. The discrepancies in the procedures were
primarily in connection with recordkeeping and did not involve spills, leaks, or
other mishandling of PCB contaminated fluids and did not damage the environment.
A thorough investigation of all collection and handling practices at East Ohio
Gas has been conducted and the Company provided the results of this
investigation to the EPA in 1997. One partial penalty assessment has been
received from the EPA, and the Company has entered into a Consent Agreement
Consent Order with the EPA. The penalty assessment was developed by EPA under
its Voluntary Disclosure Policy of April 22, 1995 and was approximately one
thousand dollars. The Company anticipates that additional penalties incurred in
connection with this matter will be mitigated as a result of the Company's self
disclosure. The amount of any liabilities in connection with this matter is not
expected to be material with respect to the Company's financial position,
results of operations or cash flows.
Estimates of liability in the environmental area are based on current
environmental laws and regulations and existing technology. The exact nature of
environmental issues which the Company may encounter in the future cannot be
predicted. Additional environmental liabilities may result in the future as more
stringent environmental laws and regulations are implemented and as the Company
obtains more specific information about its existing sites and production
facilities. At present, no estimate of any such additional liability, or range
of liability amounts, can be made. However, the amount of any such liabilities
could be material.

18. COMMITMENTS AND CONTINGENCIES

Lease arrangements of the Company 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 1995 through 1997 was not material, and future rental payments required
under leases in effect at December 31, 1997, are not material.
It is estimated that the Company's 1998 capital spending program will
amount to $714.7 million, and that approximately $312.7 million of that amount
will be directed to gas and oil producing activities. In connection with the
capital spending program, the Company has entered into certain contractual
commitments. Contractual commitments in the ordinary course of business include
requirements by CNG Energy Services to purchase capacity on nonaffiliated
pipelines to meet both committed and anticipated future long-term customer gas
supply needs.
The Company has claims and suits arising in the ordinary course of business
pending against it but, in the opinion of management and counsel, the ultimate
liability will not have a material effect on its financial position, results of
operations or cash flows.

19. DISAGGREGATED INFORMATION

In addition to operating in all phases of the natural gas business, the Company
explores for and produces oil and provides a variety of energy marketing
services.

45
<PAGE> 73
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Distribution represents the retail gas distribution subsidiaries. These
subsidiaries sell gas and/or provide transportation services to residential,
commercial and industrial customers in Ohio, Pennsylvania, Virginia and West
Virginia, and are subject to price regulation by their respective state utility
commissions.
Transmission operations include the activities of CNG Transmission, an
interstate pipeline company regulated by the FERC which provides gas
transportation, storage and related services to affiliates and to utilities and
end users in the Midwest, the Mid-Atlantic states and the Northeast. CNG
Transmission also holds a 16% general partnership interest in the Iroquois Gas
Transmission System, L.P., a limited partnership that owns and operates an
interstate natural gas pipeline that transports Canadian gas to utility and
power generation customers in New York and New England.
Exploration and production includes the results of CNG Producing and the
gas and oil production activities of CNG Transmission. These operations are
located throughout the United States and in the Gulf of Mexico. CNG Producing
also owns a working interest in a heavy oil program in Alberta, Canada.
Energy marketing services is comprised of CNG Energy Services and CNG Power
Services. CNG Energy Services markets Company-owned gas production and arranges
gas supplies, transportation, storage and related services throughout North
America. CNG Energy Services also holds the Company's ownership interests in six
independent power plants. CNG Power Services is the power marketing subsidiary
that purchases and resells electricity at market-based prices.
The activities of CNG International, CNG Retail, CNG Products and Services,
Consolidated LNG, CNG Research and CNG Coal are included in the "Other"
category. CNG International was formed in 1996 to engage in energy-related
activities outside of the United States and holds equity investments in
Australia and Latin America. CNG Retail was established in 1997 to pursue
opportunities arising from the deregulation of the energy industry at the retail
level. CNG Products and Services began operations in 1996 and provides certain
energy-related services to customers of the Company's distribution subsidiaries
and others.
Transactions between affiliates are recognized at prices which approximate
market value. Significant transactions between the operating components are
eliminated to reconcile the disaggregated information to consolidated amounts.
Identifiable assets of each component are those assets that are used in its
operations.

46
<PAGE> 74
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table represents disaggregated information pertaining to the
Company's operations:
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
Exploration Energy Corporate
and Marketing and
Distribution Transmission Production Services Other Eliminations Total
- - ---------------------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
1997
Operating revenues
Nonaffiliated
Regulated gas sales........... $1,844,221 $ -- $ -- $ -- $ 6,780 $ -- $1,851,001
Nonregulated gas sales........ -- -- 48,379 2,259,436 31,342 -- 2,339,157
Gas transportation and
storage..................... 153,503 318,086 701 7,215 -- -- 479,505
Electricity sales............. -- -- -- 594,253 279 -- 594,532
Other......................... 23,695 47,853 300,370 68,400 5,507 -- 445,825
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total nonaffiliated......... 2,021,419 365,939 349,450 2,929,304 43,908 -- 5,710,020
Affiliated...................... 5,142 121,037 356,230 176,463 15,257 (674,129) --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total operating revenues...... 2,026,561 486,976 705,680 3,105,767 59,165 (674,129) 5,710,020
Other operating expenses........ 1,682,602 246,617 381,475 3,116,964 68,100 (661,068) 4,834,690
Depreciation and amortization... 77,389 61,920 181,356 5,884 366 3,229 330,144
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating income before income
taxes......................... $ 266,570 $ 178,439 $ 142,849 $ (17,081) $ (9,301) $ (16,290) $ 545,186
========== ========== ========== ========== ========== ========== ==========
Capital expenditures............ $ 147,213 $ 49,251 $ 293,337 $ 12,865 $ 95,801 $ 10,906 $ 609,373
Identifiable assets............. $2,879,960 $1,482,652 $1,314,468 $ 757,028 $ 288,006 $ (408,420) $6,313,694
- - ---------------------------------------------------------------------------------------------------------------------------------
1996
Operating revenues
Nonaffiliated
Regulated gas sales........... $1,745,206 $ -- $ -- $ -- $ 7,017 $ -- $1,752,223
Nonregulated gas sales........ -- -- 66,126 1,026,360 -- -- 1,092,486
Gas transportation and
storage..................... 132,134 331,637 532 807 -- -- 465,110
Electricity sales............. -- -- -- 109,446 -- -- 109,446
Other......................... 25,211 51,471 226,306 70,235 1,821 -- 375,044
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total nonaffiliated......... 1,902,551 383,108 292,964 1,206,848 8,838 -- 3,794,309
Affiliated...................... 2,961 120,292 339,323 149,635 9,834 (622,045) --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total operating revenues...... 1,905,512 503,400 632,287 1,356,483 18,672 (622,045) 3,794,309
Other operating expenses........ 1,572,959 264,542 333,336 1,363,871 21,780 (614,324) 2,942,164
Depreciation and amortization... 74,132 60,107 165,715 1,681 48 2,488 304,171
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating income before income
taxes......................... $ 258,421 $ 178,751 $ 133,236 $ (9,069) $ (3,156) $ (10,209) $ 547,974
========== ========== ========== ========== ========== ========== ==========
Capital expenditures............ $ 143,050 $ 85,904 $ 247,103 $ 35,531 $ 42,570 $ 6,135 $ 560,293
Identifiable assets............. $2,902,917 $1,481,612 $1,232,992 $ 473,766 $ 94,608 $ (185,290) $6,000,605
- - ---------------------------------------------------------------------------------------------------------------------------------
1995
Operating revenues
Nonaffiliated
Regulated gas sales........... $1,594,397 $ (4,275) $ -- $ -- $ 7,257 $ -- $1,597,379
Nonregulated gas sales........ -- -- 57,778 939,946 -- -- 997,724
Gas transportation and
storage..................... 122,175 333,185 423 587 -- -- 456,370
Electricity sales............. -- -- -- 21,768 -- -- 21,768
Other......................... 22,375 36,978 116,241 58,488 2 -- 234,084
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total nonaffiliated......... 1,738,947 365,888 174,442 1,020,789 7,259 -- 3,307,325
Affiliated...................... 6,280 105,138 187,012 87,611 10,168 (396,209) --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total operating revenues...... 1,745,227 471,026 361,454 1,108,400 17,427 (396,209) 3,307,325
Other operating expenses........ 1,466,776 261,091 438,477 1,113,014 14,543 (392,668) 2,901,233
Depreciation and amortization... 70,972 59,552 123,492 1,072 -- 1,548 256,636
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating income before income
taxes......................... $ 207,479 $ 150,383 $ (200,515) $ (5,686) $ 2,884 $ (5,089) $ 149,456
========== ========== ========== ========== ========== ========== ==========
Capital expenditures............ $ 160,480 $ 81,557 $ 176,789 $ 19,567 $ -- $ 1,000 $ 439,393
Identifiable assets............. $2,645,004 $1,483,631 $1,155,092 $ 317,490 $ 54,425 $ (237,349) $5,418,293
- - ---------------------------------------------------------------------------------------------------------------------------------
</TABLE>

47
<PAGE> 75
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

20. SUPPLEMENTARY FINANCIAL INFORMATION--UNAUDITED

(A) GAS AND OIL PRODUCING ACTIVITIES (EXCLUDING COST-OF-SERVICE RATE-REGULATED
ACTIVITIES)
This information has been prepared in accordance with SFAS No. 69, "Disclosures
about Oil and Gas Producing Activities," and related SEC pronouncements.
Statement No. 69 is a comprehensive, standard set of required disclosures about
the gas and oil producing activities of publicly traded companies. The following
disclosures exclude the gas and oil producing activities subject to
cost-of-service rate regulation. Certain disclosures about these gas and oil
activities, which are exempt from the accounting methods prescribed by the SEC,
are included under "Cost-of-Service Properties" in this Note (A).

CAPITALIZED COSTS
The aggregate amounts of costs capitalized by subsidiaries for their gas and oil
producing activities, and related aggregate amounts of accumulated depreciation
and amortization, follow:
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
DECEMBER 31, 1997 1996
- - -----------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C>
Capitalized costs of
Proved properties......................................... $3,293,851 $3,057,682
Unproved properties....................................... 328,174 317,462
---------- ----------
Subtotal............................................... 3,622,025 3,375,144
---------- ----------
Accumulated depreciation of
Proved properties......................................... 2,367,105 2,224,471
Unproved properties....................................... 146,417 134,481
---------- ----------
Subtotal............................................... 2,513,522 2,358,952
---------- ----------
Net capitalized costs.................................. $1,108,503 $1,016,192
========== ==========
</TABLE>

- - --------------------------------------------------------------------------------
As described in Note 4, the Company recognized an impairment of its
Canadian oil producing properties at December 31, 1997. The non-cash charge
amounted to $10.4 million and is reflected in the amounts included above.

TOTAL COSTS INCURRED
The following costs were incurred by subsidiaries in their gas and oil producing
activities during the years 1995 through 1997:
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, 1997 1996 1995
- - --------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Property acquisition costs
Proved properties...................................... $ 14,142 $ 42,880 $ 5,824
Unproved properties.................................... 43,951 17,911 9,686
-------- -------- --------
Subtotal............................................ 58,093 60,791 15,510
Exploration costs........................................ 101,891 49,622 50,974
Development costs........................................ 118,746 125,139 102,574
-------- -------- --------
Total............................................... $278,730 $235,552 $169,058
======== ======== ========
</TABLE>

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

RESULTS OF OPERATIONS
The elements of the "results of operations for gas and oil producing activities"
that follow are as required and defined by the FASB. The Company cautions that
these standardized disclosures do not represent the

48
<PAGE> 76
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

results of operations based on its historical financial statements. In addition
to requiring different determinations of revenues and costs, the disclosures
exclude the impact of interest expense and corporate overheads.
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, 1997 1996 1995
- - --------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Revenues (net of royalties) from:
Sales to nonaffiliated companies....................... $111,181 $ 84,239 $ 60,139
Transfers to other operations.......................... 300,025 289,892 150,930
-------- -------- ---------
Total............................................... 411,206 374,131 211,069
-------- -------- ---------
Less: Production (lifting) costs......................... 65,286 55,679 40,812
Depreciation and amortization...................... 172,046 157,358 117,163
Impairment of producing properties................. 10,351 -- 226,209
Income tax expense................................. 48,987 49,367 (68,615)
-------- -------- ---------
Results of operations.................................... $114,536 $111,727 $(104,500)
======== ======== =========
</TABLE>

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

COMPANY-OWNED RESERVES (NON-COST-OF-SERVICE RESERVES)
Estimated net quantities of proved gas and oil (including condensate) reserves
in the United States and Canada at December 31, 1995 through 1997, and changes
in the reserves during those years, are shown in the two schedules which follow:
- - --------------------------------------------------------------------------------

- - --------------------------------------------------------------------------------
Included in the caption "Extensions, discoveries and other additions" for
1995 are 110 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, 1997, 1996 and 1995, include United States reserves of
1,140, 1,039 and 984 Bcf which, together with the Canadian reserves and the gas
reserves

49
<PAGE> 77
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

reported under "Cost-of-Service Properties," are as contained in reports of
Ralph E. Davis Associates, Inc., independent geologists.
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, 1997 1996 1995
- - --------------------------------------------------------------------------------------------------
(In Thousand Bbls)
<S> <C> <C> <C>
PROVED DEVELOPED AND UNDEVELOPED RESERVES* -- OIL
At January 1.............................................. 50,457 45,791 46,255
Changes in reserves
Extensions, discoveries and other additions............ 4,582 5,976 1,965
Revisions of previous estimates........................ 1,741 2,711 1,117
Production............................................. (7,312) (4,766) (3,132)
Purchases of oil in place.............................. 1,182 804 163
Sales of oil in place.................................. (23) (59) (577)
------ ------ ------
At December 31............................................ 50,627 50,457 45,791
====== ====== ======
PROVED DEVELOPED RESERVES* -- OIL
At January 1.............................................. 24,989 19,838 20,379
At December 31............................................ 37,568 24,989 19,838
*Net before royalty.
</TABLE>

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

The foregoing proved developed and undeveloped oil reserves at December 31,
1997, 1996 and 1995 include United States reserves of 44,160, 41,818 and 39,964
thousand barrels, respectively. These, together with the Canadian reserves, are
as contained in reports of Ralph E. Davis Associates, Inc.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES
THEREIN
The following tabulation has been prepared in accordance with the FASB's rules
for disclosure of a standardized measure of discounted future net cash flows
relating to Company-owned proved gas and oil reserve quantities.
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
DECEMBER 31, 1997 1996 1995
- - -------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Future cash inflows..................................... $3,197,532 $4,022,381 $2,668,837
Less: Future development and production costs........... 658,281 711,067 659,532
Future income tax expense........................ 766,233 1,049,234 602,158
---------- ---------- ----------
Future net cash flows................................... 1,773,018 2,262,080 1,407,147
Less annual discount (10% a year)....................... 606,509 830,083 565,404
---------- ---------- ----------
Standardized measure of discounted future net cash
flows................................................. $1,166,509 $1,431,997 $ 841,743
========== ========== ==========
</TABLE>

- - --------------------------------------------------------------------------------
In the foregoing determination of future cash inflows, sales prices for gas
were based on contractual arrangements or market prices at each year-end. Prices
for oil were based on average prices received from sales in the month of
December each year. Future costs of developing and producing the proved gas and
oil reserves reported at the end of each year shown were based on costs
determined at each such year-end, assuming the continuation of existing economic
conditions. Future income taxes were computed by applying the appropriate
year-end or future statutory tax rate to future pretax net cash flows, less the
tax basis of the properties involved, and giving effect to tax deductions, or
permanent differences and tax credits.
It is not intended that the FASB's standardized measure of discounted
future net cash flows represent the fair market value of the Company's proved
reserves. The Company cautions that the disclosures shown are based on estimates
of proved reserve quantities and future production schedules which are
inherently

50
<PAGE> 78
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

imprecise and subject to revision, and the 10% discount rate is arbitrary. In
addition, present costs and prices are used in the determinations and no value
may be assigned to probable or possible reserves.
The following tabulation is a summary of changes between the total
standardized measure of discounted future net cash flows at the beginning and
end of each year.

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

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, 1997 1996 1995
- - -------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Standardized measure of discounted future net cash flows
at January 1.......................................... $1,431,997 $ 841,743 $ 704,492
Changes in the year resulting from
Sales and transfers of gas and oil produced during the
year, less production costs........................ (345,920) (318,583) (170,257)
Prices and production and development costs related to
future production.................................. (660,014) 632,118 150,634
Extensions, discoveries and other additions, less
production and development costs................... 256,366 295,236 181,664
Previously estimated development costs incurred during
the year........................................... 38,409 62,706 62,958
Revisions of previous quantity estimates.............. 101,352 106,800 8,336
Accretion of discount................................. 209,210 119,555 98,736
Income taxes.......................................... 159,528 (306,290) (70,927)
Purchases and sales of proved reserves in place-net... 40,815 112,601 1,794
Other (principally timing of production).............. (65,234) (113,889) (125,687)
---------- ---------- ---------
Standardized measure of discounted future net cash flows
at December 31........................................ $1,166,509 $1,431,997 $ 841,743
========== ========== =========
- - -------------------------------------------------------------------------------------------------------------------
</TABLE>

COST-OF-SERVICE PROPERTIES
As previously stated, activities subject to cost-of-service rate regulation are
excluded from the foregoing information. At December 31, 1997 and 1996, net
capitalized costs of cost-of-service properties amounted to $8.4 million and
$10.0 million, respectively. Related proved reserves of gas are located in the
United States and amounted to 42, 43 and 56 Bcf at December 31, 1997, 1996 and
1995. There were no cost-of-service oil reserves at December 31, 1997, 1996 or
1995. Gas production for the years 1997, 1996 and 1995 amounted to 3, 3 and 4
Bcf, respectively. Oil production for 1995 amounted to 17,000 barrels.
Future revenues associated with production of the foregoing gas reserves
would be based upon cost-of-service ratemaking and historical asset costs, with
rate of return levels determined by various state regulatory commissions.

(B) QUARTERLY FINANCIAL DATA
A summary of the quarterly results of operations for the years 1997 and 1996
follows. Per share amounts for the first three quarters of 1997 and all 1996
quarters have been restated in connection with the Company's adoption of SFAS
No. 128. 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

51
<PAGE> 79
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

the Company. Seasonal fluctuations are further influenced by the timing of price
relief granted under regulation to compensate for certain past cost increases.
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
Quarter
-----------------------------------------------------------------------------
First Second Third Fourth
- - --------------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C>
1997
Total operating revenues................... $1,698,599 $1,030,854 $1,130,477 $1,850,090
Operating income before income taxes....... 280,688 76,990 26,859 160,649
Net income................................. 171,491 38,985 4,538 89,366
Earnings per common share -- basic......... 1.81 .41 .05 .94
Earnings per common share -- diluted*...... 1.74 .41 .05 .92
1996
Total operating revenues................... $1,315,084 $ 654,950 $ 595,057 $1,229,218
Operating income before income taxes....... 302,176 71,949 11,045 162,804
Net income (loss).......................... 180,800 34,617 (5,118) 87,974
Earnings (loss) per common
share -- basic........................... 1.93 .37 (.05) .93
Earnings (loss) per common
share -- diluted*........................ 1.87 .37 (.05) .91
</TABLE>

* 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.
- - --------------------------------------------------------------------------------

(C) COMMON STOCK MARKET PRICES AND RELATED MATTERS
At December 31, 1997, there were 35,498 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 1997 and
1996 follow. Restrictions on the payment of dividends are discussed in Note 13.
- - --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
Quarter
-------------------------------------------------------------------------
First Second Third Fourth
- - -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Market Price Range
1997--High.................................... $ 57 3/4 $ 54 7/8 $ 60 11/16 $ 60 15/16
--Low................................... $ 49 5/8 $ 47 3/8 $ 53 9/16 $ 52 5/16
1996--High.................................... $ 47 1/8 $ 52 1/4 $ 57 1/8 $ 59 5/8
--Low................................... $ 41 1/2 $ 43 1/2 $ 49 $ 51 1/8
Dividends Declared per Share
1997.......................................... $ .485 $ .485 $ .485 $ .485
1996.......................................... $ .485 $ .485 $ .485 $ .485
</TABLE>

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

52
<PAGE> 80
PLEASE MARK YOUR 0693
[X] VOTES AS IN THIS
EXAMPLE.

- - --------------------------------------------------------------------------------
THE BOARD OF DIRECTORS RECOMMENDS A VOTE FOR ITEMS 1 AND 2 AND AGAINST ITEM 3.
- - --------------------------------------------------------------------------------
FOR WITHHELD
1. ELECTION OF
DIRECTORS [ ] [ ]
(SEE REVERSE)
For, except vote withheld from the following nominee(s):

- - -----------------------------------------
FOR AGAINST ABSTAIN
2. Ratification of
Price Waterhouse LLP [ ] [ ] [ ]
as Independent
accountants.

FOR AGAINST ABSTAIN
3. Adoption of a shareholder-
proposed resolution [ ] [ ] [ ]
regarding the rights plan.

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

Change [ ] Attend [ ]
of Meeting
Address

SIGNATURE(S) ________________________________________ DATE __________
NOTE: Please sign exactly as name appears hereon. Joint owners should each
sign. When signing as attorney, executor, administrator, trustee or
guardian, please give full title as such.

- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
FOLD AND DETACH HERE. PLEASE VOTE, SIGN, AND RETURN THE ABOVE PROXY OR
VOTE ELECTRONICALLY BY TELEPHONE

CONSOLIDATED NATURAL GAS COMPANY

ANNUAL MEETING OF STOCKHOLDERS

Dear Stockholder,

Consolidated Natural Gas Company encourages you to take advantage of a new and
convenient way by which you can vote your shares--electronically through the
telephone. This eliminates the need to return the proxy card.

To vote your shares electronically through the telephone:

- On a touch-tone telephone call 1-800-OK2-VOTE (1-800-652-8683)
- 24 hours a day, 7 days a week
- Listen to the recording for instructions
- Use the control number printed in the box above to access the system
- Use your phone key pad to vote

Your electronic vote authorizes the named proxies in the same manner as if you
marked, signed, dated and returned the proxy card. If you choose to vote your
shares electronically, there is no need for you to mail back your proxy card.

YOUR VOTE IS IMPORTANT. THANK YOU FOR VOTING.
<PAGE> 81
CONSOLIDATED
CNG(R) NATURAL GAS
COMPANY

CONSOLIDATED NATURAL GAS COMPANY
PROXY SOLICITED ON BEHALF OF THE BOARD OF DIRECTORS OF THE COMPANY
FOR THE ANNUAL MEETING OF STOCKHOLDERS APRIL 14, 1998

The undersigned hereby appoints G.A. Davidson, Jr., D.M. Westfall and S.E.
P Williams, and each or any of them, proxies with full power of substitution
R to vote the stock of the undersigned, as directed hereon, at the Annual
O Meeting of Stockholders of CONSOLIDATED NATURAL GAS COMPANY to be held at
X the Harborside Hyatt Conference Center and Hotel, 101 Harborside Drive,
Y Boston, Massachusetts 02128 on Tuesday, April 14, 1998, at 10:00 a.m.
(Eastern Time), and at any adjournment thereof, and, in their discretion,
on any other matters that may properly come before the Meeting.

(change of address)
Election of Directors _____________________________
_____________________________
Nominees: 1. J.W. Connolly, _____________________________
2. G.A. Davidson, Jr. _____________________________
3. R.P. Simmons (If you have written in the
above space, please mark the
Change of Address Box on the
reverse side of this card.)

PLEASE SPECIFY YOUR CHOICES BY MARKING THE APPROPRIATE BOXES, SEE REVERSE
SIDE. WHEN PROPERLY EXECUTED, THIS PROXY WILL BE VOTED IN ACCORDANCE WITH
YOUR INSTRUCTIONS, OR, IF YOU GIVE NO INSTRUCTIONS, THIS PROXY WILL BE
VOTED FOR ITEMS 1 AND 2 AND AGAINST ITEM 3.

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SEE REVERSE
SIDE
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FOLD AND DETACH HERE

FEBRUARY 23, 1998

Dear Stockholder:

Effective February 24, 1997, First Chicago Trust Company of New York (First
Chicago) began serving CNG stockholders as CNG's transfer agent, registrar and
administrator of the CNG Dividend Reinvestment Plan.

You may call First Chicago at any time toll-free at 1-800-414-6443, customer
service representatives are available between 8:30 a.m. and 7:00 p.m. Eastern
Time. You may correspond with the agent by writing to First Chicago Trust
Company, PO Box 2500, Jersey City, NJ 07303-2500, via the Internet at
http://www.fctc.com, or via e-mail at [email protected].

Sincerely,

/s/ GEORGE A. DAVIDSON, JR.
-----------------------------
George A. Davidson, Jr.
Chairman of the Board and
Chief Executive Officer