<PAGE>   1
                                                      Commission File No. 1-1098

As filed with the United States Securities and Exchange Commission on March 14,
                                     1997.


                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    FORM 10-K

                  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
[X]                   OF THE SECURITIES EXCHANGE ACT OF 1934

                   For the Fiscal Year Ended DECEMBER 31, 1996
                                       or
                TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934
[ ]
                  For the Transition Period from _____ to _____

             T H E   C O L U M B I A   G A S   S Y S T E M,   I N C.
             -------------------------------------------------------

             (Exact name of registrant as specified in its charter)

<TABLE>
<S>                                                               <C>
                          Delaware                                              13-1594808
(State or other Jurisdiction of incorporation or organization)    (I.R.S. Employer Identification No.)

    12355 Sunrise Valley Drive, Suite 300, Reston, VA                           20191-3420
        (Address of principal executive offices)                                (Zip Code)
</TABLE>

        Registrant's telephone number, including area code (703)295-0300

Securities registered pursuant to Section 12(b) of the Act:

                                                      Name of Each Exchange
  Title of Each Class                                  on Which Registered
  -------------------                                 ---------------------
Common Stock, $10 Par Value...........               New York Stock Exchange


Debentures
6.39% Series A due November 28, 2000
6.61% Series B due November 28, 2002
6.80% Series C due November 28, 2005
7.05% Series D due November 28, 2007
7.32% Series E due November 28, 2010
7.42% Series F due November 28, 2015
7.62% Series G due November 28, 2025


Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the proceeding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days: Yes _X_ or No ___.

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]

The aggregate market value of the outstanding common shares of the Registrant
held by nonaffiliates as of January 31, 1997, was $3,586,056,000. For purposes
of the foregoing calculation, all directors and/or officers have been deemed to
be affiliates, but the registrant disclaims that any of such directors and/or
officers is an affiliate.

The number of shares outstanding of each class of common stock as of January 31,
1997, was: Common Stock $10 Par Value: 55,343,729 shares outstanding.

                       Documents Incorporated by Reference

Part III of this report incorporates by reference the Registrant's Proxy
Statement relating to the 1997 Annual Meeting of Stockholders.
<PAGE>   2
                                    CONTENTS

<TABLE>
<CAPTION>
                                                                                             Page
Part I                                                                                        No.
                                                                                             ----
<S>                                                                                          <C>
        Item 1.  Business.................................................................     3

        Item 2.  Properties...............................................................     7

        Item 3.  Legal Proceedings........................................................     9

        Item 4.  Submission of Matters to a Vote of Security Holders......................    12

Part II

        Item 5.  Market for the Registrant's Common Equity 
                            and Related Stockholder Matters...............................    12

        Item 6.  Selected Financial Data..................................................    13

        Item 7.  Management's Discussion and Analysis of Financial Condition and
                            Results of Operations.........................................    15

        Item 8.  Financial Statements and Supplementary Data..............................    40

        Item 9.  Change In and Disagreements with Accountants on Accounting and
                            Financial Disclosure..........................................    75

Part III

        Item 10. Directors and Executive Officers of the Registrant.......................    75

        Item 11. Executive Compensation...................................................    76

        Item 12. Security Ownership of Certain Beneficial Owners and Management...........    76

        Item 13. Certain Relationships and Related Transactions...........................    76

Part IV

        Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K..........    76

        Undertaking made in Connection with 1933 Act Compliance on Form S-8...............    76

        Signatures........................................................................    77
</TABLE>
<PAGE>   3
                                     PART I

ITEM 1.  BUSINESS

General

The Columbia Gas System, Inc. (Columbia) and its subsidiaries comprise one of
the nation's largest integrated natural gas systems engaged in natural gas
transmission, natural gas distribution, and exploration for and production of
natural gas and oil. Columbia is also engaged in related energy businesses
including the marketing of natural gas, the generation of electricity, primarily
fueled by natural gas, and the distribution of propane. Columbia, organized
under the laws of the State of Delaware on September 30, 1926, is a registered
holding company under the Public Utility Holding Company Act of 1935, as
amended, (1935 Act) and derives substantially all its revenues and earnings from
the operating results of its 18 direct subsidiaries. Columbia owns all of the
securities of its subsidiaries except for approximately 8 percent of the stock
in Columbia LNG Corporation. Columbia and its subsidiaries are sometimes
collectively referred to herein as the System.

Columbia and its principal pipeline subsidiary, Columbia Gas Transmission
Corporation (Columbia Transmission), emerged from bankruptcy on November 28,
1995, after filing separate petitions for protection under Chapter 11 of the
Federal Bankruptcy Code (Bankruptcy Code) on July 31, 1991. During the
bankruptcy period both Columbia and Columbia Transmission were
debtors-in-possession under the Bankruptcy Code and continued to operate their
businesses in the normal course subject to the jurisdiction of the United States
Bankruptcy Court for the District of Delaware.

Transmission and Storage Operations

Columbia's two interstate pipeline subsidiaries, Columbia Transmission and
Columbia Gulf Transmission Company (Columbia Gulf), operate a 23,100-mile
pipeline network extending from offshore in the Gulf of Mexico to Lake Erie, New
York and the eastern seaboard. In addition, Columbia Transmission operates one
of the nation's largest underground natural gas storage systems. The
transmission subsidiaries serve directly or indirectly eight million customers
in fifteen northeastern, midatlantic, midwestern, and southern states and the
District of Columbia. Columbia Gulf's pipeline system, extends from offshore
Louisiana to West Virginia and transports a major portion of the gas delivered
by Columbia Transmission. It also transports gas for third parties within the
production areas of the Gulf Coast.

Columbia Transmission provides an array of competitively priced natural gas
transportation and storage services for local distribution companies and
industrial and commercial customers who contract directly with producers or
marketers for their gas supplies.

Columbia LNG Corporation is a partner with Potomac Electric Power Company in the
Cove Point LNG Limited Partnership (Partnership). The Partnership owns one of
the largest natural gas peaking and storage facilities in the United States
located at Cove Point, Maryland. The facility enables liquefied natural gas to
be stored until needed for the winter peak-day requirements of utilities and
other large gas users. The facility has the capacity to liquefy natural gas at a
rate of 15,000 Mcf of natural gas per day.

Distribution Operations

Columbia's five distribution subsidiaries provide natural gas service to
approximately 2 million residential, commercial and industrial customers in
Ohio, Pennsylvania, Virginia, Kentucky and Maryland. The distribution
subsidiaries sell gas to high priority (mostly residential) customers and
transport gas for certain industrial and commercial customers who purchase gas
from other sources. Approximately 31,100 miles of distribution pipelines serve
these major markets.

Exploration and Production Operations

Columbia's exploration and production subsidiary, Columbia Natural Resources,
Inc. (Columbia Resources), explores for, develops and produces natural gas and
oil in Appalachia. As of December 31, 1996, Columbia Resources held interest in
more than 2 million net acres of gas and oil leases and had proved gas reserves
of approximately 645 Bcf. Columbia sold its southwest exploration and production
subsidiary effective December 31, 1995. For additional information, see Item 7,
page 33.


                                        3
<PAGE>   4
ITEM 1.  BUSINESS (Continued)


Marketing, Propane and Power Generation Operations

Columbia Energy Services Corporation (Columbia Energy), Columbia's nonregulated
natural gas marketing company, provides an array of supply and fuel management
services to distribution companies, independent power producers and other large
end users both on and off Columbia's transmission and distribution pipeline
systems. Columbia Energy opened the Columbia Energy Market Center in 1994 to
provide one-stop shopping for natural gas supply and transportation services to
help customers better manage their energy costs. Columbia Energy formed a
wholly-owned subsidiary, Columbia Service Partners, Inc. (Columbia Service), to
provide a variety of new nonregulated services to both homeowners and
businesses. In the second quarter of 1996, Columbia Service introduced Appliance
Partner, a service which offers customers appliance repair from qualified
independent contractors for a monthly premium. Another service provided by
Columbia Service is Gas Line Guarantee, which provides maintenance for gas
service lines running from the street to the house. Columbia Service has also
initiated a billing insurance program, Payment Partner, for customers within
certain areas of the distribution subsidiaries' service territory. As of
year-end 1996, Columbia Service had nearly 26,100 customers among the three
programs. In the future, Columbia Service expects to complement these services
with warranty and energy management services to commercial and industrial
customers. These new programs are part of Columbia's ongoing effort to become a
full service provider of energy and energy-related services.

TriStar Ventures Corporation (TriStar), a wholly-owned subsidiary of Columbia,
is involved in three cogeneration projects that produce both electricity and
useful thermal energy. These projects are fueled principally by natural gas.
TriStar holds various interests in these facilities that have a total capacity
of nearly 250 megawatts.

Columbia Propane Corporation and Commonwealth Propane, Inc., wholly-owned
subsidiaries of Columbia, sell propane at wholesale and retail to 79,650
customers in parts of ten eastern states and the District of Columbia. In total,
the propane companies sold nearly 76 million gallons of propane in 1996.

In 1996, Columbia formed Columbia Network Services Corporation (Columbia
Network), a wholly-owned subsidiary, to provide telecommunications and
information services. Columbia Network's primary focus is to assist personal
communications service (PCS) and other microwave radio service licensees in
locating and constructing antenna facilities as well as maintaining and managing
PCS sites for the licensees. In October 1996, Columbia Network entered into an
agreement with SABRE Decision Technologies, a division of The SABRE Group, Inc.
to jointly develop a centralized electronic energy data exchange. During the
initial phase, a standardized electronic bulletin board (EBB) will be designed
for use by the natural gas industry. The EBB will be consistent with
FERC-mandated business standards for electronic gas transportation transactions
and provide a single centralized interface that customers can utilize to conduct
business with a multitude of gas transportation service providers (TSPs). This
type of system is expected to reduce the overall transaction costs of trading
and transporting gas, support the standardization of gas transactions for the
natural gas industry, and allow TSPs to concentrate on their core businesses.
Columbia Network also plans to offer energy management services relating to the
collection and management of customer energy usage information. In addition,
these services may provide opportunities for real-time interactive
communications with customers with respect to a wide variety of information,
products, and services not exclusively energy-related.

For additional discussion of Columbia's business segments, including financial
information for the last three fiscal years, see Item 7, pages 15 through 39 and
Note 17 on pages 66 through 68 of Item 8.

Competition and Business Strategies

The natural gas and energy markets are undergoing tremendous change. Over the
past ten years open access to natural gas supplies over interstate pipelines has
developed and the commodity price of gas has been deregulated. During this
period, distribution companies, larger industrial and commercial customers and
marketers began to purchase gas directly from producers and marketers and an
open competitive market for gas supplies emerged. This separation or
"unbundling" of the transportation and other services offered by pipelines
allows customers to select the services they want independent from the purchase
of the commodity. This "unbundling" of services and deregulation of the
commodity price is occurring at the distribution company level as well.
Columbia's distribution subsidiaries are involved in pilot programs that provide
residential customers the opportunity to purchase their natural gas requirements
from third parties and use the distribution subsidiaries for transportation
services. At the same time that the natural gas markets are evolving, the
markets for competing energy sources are also changing. Open access to
interstate


                                        4
<PAGE>   5
ITEM 1.  BUSINESS (Continued)

transmission of electricity is under investigation by the Federal Energy
Regulatory Commission (FERC) and, if introduced, could result in increased
competition in the market for electricity. The energy market of the future may
be characterized by open competition not only in the market for supply of a
particular commodity but also open competition between interchangeable fuels.
For additional information, regarding competition, see Item 7.

In order to capitalize on the opportunities presented by this increasingly
competitive environment, Columbia's management is developing a more responsive,
entrepreneurial, customer-focused organization which will utilize Columbia's
core asset strengths, its expansive customer base and its knowledge and
experience in the energy markets to remake Columbia into a "total energy
company" - a leading provider of energy and energy services. To achieve this
goal, Columbia has developed the following strategic initiatives:

            Capitalize on Core Asset Strengths. Columbia intends to focus on and
expand its core businesses, allocating approximately 87% of planned 1997 capital
investment to the transmission and distribution segments. Consistent with this
focus Columbia has undertaken a $270 million expansion of Columbia
Transmission's storage and transportation systems that will be phased in over a
three year period beginning in late 1997. Columbia's sale of its southwest
exploration and production subsidiary, Columbia Gas Development Corporation, is
consistent with this new strategy, following a determination that the strategic
value to Columbia of drilling for gas in the Southwest had diminished. In
contrast, the reserves held by Columbia's Appalachian exploration and production
subsidiary, Columbia Resources, have greater strategic value due to their
location and may even be expanded if the appropriate business opportunities
present themselves.

            Exploit Synergies. Unlike the structure of many of its peers,
Columbia's distribution, storage and exploration and production operations form
a grid connected from within by Columbia Transmission. Columbia is embarking on
a system-wide strategy that will provide customers with a variety of unbundled
gas supply services - gathering, processing, transportation, storage,
distribution and other energy delivery services. Columbia is also seeking to
capitalize on the efficiencies of its integrated system through initiatives with
regulators designed to promote rate structures that will reward Columbia's
transmission and distribution subsidiaries for enhanced productivity and
efficiency.

            Develop Nonregulated Energy Business. Columbia's extensive presence
in the northeast, mid-atlantic and midwestern regions of the country provides
significant opportunities to offer customers a wide variety of nonregulated
energy-related products and services. Through Columbia Energy, Columbia Service
and Columbia Network, Columbia expects to offer nonregulated energy-related
products and services to all energy consumers within its wholesale and retail
market area.

            Streamline Organizational Structure. In 1996, Columbia's
subsidiaries completed a top-down review of their management structure and
operations in an effort to streamline their organizational structure and improve
customer service. The studies examined all aspects of Columbia's operations
including the configuration and location of its management. The benefits of this
reengineering initiative, called Project Phoenix, are beginning to be realized
through cost savings and improved efficiencies.

            Implement CVA. An integral part of Columbia's financial strategy is
the recent application of a value added approach, called Columbia Value Added
(CVA), to all of its businesses. CVA is a financial process as well as a
financial measure that determines whether the anticipated return on a business
activity or project exceeds its risk adjusted capital cost. All
discretionary capital expenditures will be subject to the CVA process. This new
management tool aided Columbia in its decisions to allocate capital to Columbia
Transmission's planned expansion, as discussed in Item 7, page 21, and to divest
Columbia Development. CVA is also being employed in Columbia's strategic
planning process and in the setting of management compensation levels.

            Maintain Financial Flexibility. As a result of its bankruptcy
recapitalization in late-1995, Columbia achieved one of the lowest average costs
of debt in the natural gas industry (7.03%) with an average maturity of 14 years
and, as of year-end 1996, had a 56% ratio of long-term debt to total
capitalization. Columbia's long-term debt rating was recently upgraded by Fitch
Investor Service LP to BBB+, from BBB, and is currently rated Baa3 by Moody's
Investors Services and BBB by Standard & Poor's Corporation. One of management's
objectives is to improve the quality of its credit rating over time and to
better position Columbia to take advantage of business opportunities as they
arise. However, there can be no assurance that Columbia will be successful at
improving or maintaining its credit


                                        5
<PAGE>   6
ITEM 1.  BUSINESS (Continued)

quality or debt ratios or that such credit ratings will continue for any given
period of time or that they will not be revised downward or withdrawn entirely
by these rating agencies. Credit ratings reflect only the views of the rating
agencies, whose methodology and the significance of their ratings may be
obtained from them.

            The foregoing discussion includes "forward looking statements"
within the meaning of Section 27A of the Securities Act of 1933 and Section 21E
of the Securities Exchange Act of 1934. Although Columbia believes that its
expectations are based on reasonable assumptions, it can give no assurance that
its goals or strategies will be achieved. Security holders and prospective
security holders should understand that several factors govern whether any
forward-looking statement contained herein will be or can be achieved. Important
factors, many of which are beyond the control of Columbia, that could cause
actual results to differ materially from those in the forward looking statements
or projections included herein include regulatory actions, the pace of
deregulation of domestic retail natural gas and electricity markets, the timing
and extent of change in commodity prices for all forms of energy and the timing
and extent of Columbia's efforts to implement changes planned by management.

Other Relevant Business Information

The System's customer base is broadly diversified, with no single customer
accounting for a significant portion of revenues.

Certain subsidiaries file reports with various federal agencies containing
estimates of company-owned oil and gas reserves. These estimates are generally
consistent, but not always comparable, to those reported in the 1996 Annual
Report to Shareholders.

As of January 31, 1997, the System had 9,274 full-time employees of which 1,948
are subject to collective bargaining agreements.

Information relating to environmental matters is detailed in Item 7 pages 23
through 24, page 29 and in Item 8, Note 14F on pages 63 through 65.

For a listing of the direct subsidiaries of Columbia and their lines of business
refer to Exhibit 21.


                                        6
<PAGE>   7
ITEM 2.  PROPERTIES

Information relating to properties of subsidiary companies is detailed below and
on page 8 and page 48 of Item 8 under Note 1E. The System also owns coal
interests in the Appalachian area. Assets under lien and other guarantees are
described on page 63 in Note 14C of Item 8.

Neither Columbia nor any subsidiary knows of material defects in the title to
any real properties of the subsidiaries of Columbia or of any material adverse
claim of any right, title, or interest therein, pending or contemplated.
Substantially all of Columbia Transmission's property has been pledged to
Columbia as security for First Mortgage Bonds issued by Columbia Transmission to
Columbia.

                        EXPLORATION AND DEVELOPMENT DATA


Acreage - At December 31, 1996


<TABLE>
<CAPTION>
                       Developed Acreage           Undeveloped Acreage
                  -------------------------       ---------------------
                    Gross            Net           Gross          Net
                  ---------       ---------       -------       -------
<S>               <C>             <C>             <C>           <C>    
Appalachian...    1,635,443       1,544,500       623,125       493,368
                  =========       =========       =======       =======
</TABLE>


Net Wells Completed - 12 Months Ended December 31

<TABLE>
<CAPTION>
             Exploratory            Development                  Total
         ------------------     ------------------       --------------------
         Productive     Dry     Productive     Dry       Productive       Dry
         ----------     ---     ----------     ---       ----------       ---
<S>      <C>            <C>     <C>            <C>       <C>              <C>
1996.....     0          0          19           8          19(a)           8
1995.....     4          4          64          21          68(a)          25
1994.....     3          9          78          14          81(a)          23
</TABLE>

Productive and Drilling Wells - At December 31, 1996

<TABLE>
<CAPTION>
              Production Wells
---------------------------------------------
     Gross(b)                       Net               Wells Drilling
------------------          -----------------        ----------------
 Gas           Oil           Gas          Oil        Gross        Net
-----          ---          -----         ---        -----        ---
<C>            <C>          <C>           <C>        <C>          <C>
6,115          128          5,627          80          17          7
</TABLE>


(a)   Includes 1 net horizontal well in 1996, 18 net horizontal wells in 1995
      and 17 net horizontal wells in 1994.

(b)   Includes 773 multiple completion gas wells, all of which are included as
      single wells in the table.

      Also includes 1 gross productive horizontal well.


                                        7
<PAGE>   8
            GAS PROPERTIES OF SUBSIDIARIES - AS OF DECEMBER 31, 1996

<TABLE>
<CAPTION>
                                                                         Miles of Pipeline          Compressor Stations 
                                                 Underground      ------------------------------    --------------------
                                                   Storage        Gathering                                    Installed
                                               ----------------      and        Trans-    Distri-              Capacity 
            Subsidiaries                State  Acreage    Wells    Storage     mission    bution    Number        (hp)
-------------------------------------   -----  -------    -----   ---------    -------    ------    ------     ---------
<S>                                     <C>    <C>        <C>     <C>          <C>       <C>        <C>       <C>
Columbia Gas of Kentucky, Inc........    KY          -        -          -          -     2,316        -             -
Columbia Gas of Maryland, Inc........    MD          -        -          -          -       593        -             -
Columbia Gas of Ohio, Inc............    OH          -        -          -          -    17,621        -             -
Columbia Gas of Pennsylvania, Inc....    PA      3,364        8          4          -     6,816        1           800
Commonwealth Gas Services, Inc.......    VA          -        -          -          -     3,725        -             -
Columbia Gas Transmission 
  Corporation........................    DE          -        -          -          3         -        -             -
                                         KY          -        -        932        758         -        9        19,470
                                         MD        945        -         22        227         -        1        12,000
                                         NJ          -        -          -         69         -        -             -
                                         NY     26,083      143         58        486         -        4         8,190
                                         NC          -        -          -          1         -        1         1,200
                                         OH    486,810    2,463      2,764      4,062         -       30       101,441
                                         PA     63,806      263        615      2,062         -       29        66,555
                                         VA          -        -        130      1,123         -       11        56,630
                                         WV    293,204      815      3,038      2,519         -       54       303,273
Columbia Gulf Transmission Company...    AR          -        -          -          8         -        -             -
                                         KY          -        -          -        716         -        2        70,290
                                         LA          -        -          -      2,041         -        6       201,200
                                         MS          -        -          -        659         -        3       118,800
                                         TN          -        -          -        556         -        2        83,000
                                         TX          -        -          -        200         -        -             -
                                         WY          -        -          -         10         -        -             -
Columbia Natural Resources, Inc......    KY          -        -        434          -         -        -             -
                                         MI          -        -          6          -         -        -             -
                                         NY          -        -          2          -         -        -             -
                                         OH          -        -        102          -         -        -             -
                                         PA          -        -         11          -         -        -             -
                                         VA          -        -         25          -         -        -             -
                                         WV          -        -        176          -         -        -             -
                                               -------    -----      -----     ------    ------      ---     ---------
Total................................          874,212    3,692      8,319     15,500    31,071      153     1,042,849
                                               =======    =====      =====     ======    ======      ===     =========
</TABLE>

NOTE:         This table excludes minor gas properties and all construction work
              in progress. The titles to the real properties of the subsidiaries
              of Columbia have not been examined for the purpose of this
              document. Neither Columbia nor any subsidiary knows of material
              defects in the title to any of the real properties of the
              subsidiaries of Columbia or of any material adverse claim of any
              right, title, or interest therein, pending or contemplated.
              Substantially all of Columbia Transmission's property has been
              pledged to Columbia as security for First Mortgage Bonds issued by
              Columbia Transmission to Columbia.


                                        8
<PAGE>   9
ITEM 3. LEGAL PROCEEDINGS

I.        Purchase and Production Matters

                  A.    Matters that have been resolved

                        Daniel Garshman v. Columbia Gas Transmission Corp., No.
ATL-L-000172-88, (Sup. Ct. of N.J. 1993). As reported in the Quarterly Report on
Form 10-Q for the third quarter of 1996, the parties proposed a resolution to
this dispute which was approved by the U. S. Bankruptcy Court for the District
of Delaware (the "Bankruptcy Court"). The resolution of this case did not have a
material effect on the financial condition of Columbia.

                 B.  Pending Producer Matters

                     1. Estimation Proceedings. Claims by certain producers for
damages resulting from the rejection of gas purchase contracts remain unresolved
as discussed in the Management's Discussion and Analysis of Financial Condition
and Results of Operations section of this Report.

                     2. New Ulm and Fox v. Mobil Oil Corp., Columbia Gas
Transmission Corp. and Columbia Gulf Transmission Co., C.A. No. 88-V-655 (155th
Judicial Dist. Ct. of Austin County, TX). New Ulm alleged Columbia Transmission
incorrectly paid for gas on the basis of Columbia Transmission's market-out
price rather than the higher price New Ulm claimed was available to it under gas
contracts.

                     After the Bankruptcy Court entered an order modifying the
automatic stay provided under the Federal Bankruptcy Code, jury trial began in
Texas state court on June 22, 1992, and concluded with a verdict against
Columbia Transmission on July 2, 1992 in the amount of approximately $5.6
million, including interest. Thereafter, Columbia Transmission appealed to the
Court of Appeals for the First District of Texas.

                     On July 28, 1994, the Court of Appeals found that evidence
proffered by Columbia Transmission was improperly excluded from trial.
Consequently, the Court of Appeals reversed the trial court's judgment and
remanded the matter to the trial court for proceedings not inconsistent with the
Court of Appeals's opinion. On January 11, 1996, the Texas Supreme Court granted
both Columbia Transmission's and New Ulm's application for writ of error. On
October 18, 1996, the Texas Supreme Court reversed the judgment of the Court of
Appeals on New Ulm's contract interpretation claim and rendered judgment in
favor of Columbia Transmission on that issue. The Texas Supreme Court also
affirmed, in part, the appellate court's judgment by remanding New Ulm's fraud
claim to the trial court for further proceedings. The Texas Supreme Court denied
New Ulm's request for rehearing on December 13, 1996 on the contract
interpretation claim, and on February 3, 1997 issued the mandate of its judgment
to the Texas trial court.

                     3. New Bremen Corp. v. Columbia Gas Transmission Corp. and
Columbia Gulf Transmission Co., No. 88V-631 (Dist. Ct. Austin County, TX). On
November 16, 1988, New Bremen filed a complaint alleging it is entitled to a
higher price than the market-out price Columbia Transmission paid for past
periods under the same gas purchase contract price provision involved in the New
Ulm case discussed above. On January 10, 1989, Columbia Transmission removed the
case to the United States District Court for the Southern District of Texas (No.
H-89-0072).

                     By order entered December 7, 1992, the Bankruptcy Court
modified the automatic stay provided under the Federal Bankruptcy Code to allow
the U.S. District Court to decide the pending motions for summary judgment. On
August 11, 1995, an order was entered granting Columbia Transmission's motion
for partial summary judgment and denying New Bremen's motion for partial summary
judgment on the issue of contract interpretation. On August 29, 1995, the U.S.
District Court denied New Bremen's motion to withdraw and set aside its August
11, 1995 order, but stated that it would withdraw and vacate its order if the
Bankruptcy Court determined that it was in violation of the automatic stay. On
November 2, 1995, the Bankruptcy Court denied New Bremen's motion for an order
that the August 11, 1995 order was a violation of the automatic stay. The U.S.
District Court, on March 12, 1996, acting upon a motion filed by Columbia
Transmission, entered an order finding that there was no just reason to delay
entry of judgment and therefore entered final judgment of its August 11, 1995
order which granted Columbia Transmission's motion for partial summary judgment.

                     New Bremen appealed the U.S. District Court's grant of
partial summary judgment to the U.S. Court of Appeals for the Fifth Circuit. On
February 10, 1997, the Fifth Circuit denied New Bremen's appeal and upheld the
U. S. 


                                        9
<PAGE>   10
ITEM 3.  LEGAL PROCEEDINGS (Continued)

District Court's grant of partial summary judgment in favor of Columbia
Transmission on the contract pricing issue. Columbia Transmission will seek to
have New Bremen's claim allowed by the Bankruptcy Court in accordance with the
Fifth Circuit decision and the claims mediator's report and recommendations
issued in the claims estimation proceedings (resolving issues not covered by the
Fifth Circuit decision).

II.              Regulatory Matters

                 A.  Matters that have been resolved

                 Tennessee Gas Pipeline Take-or-Pay Transition Cost Recovery
Filing, Docket No. RP96-61. As reported in the Quarterly Report on Form 10-Q for
the third quarter of 1996, on July 22, 1996, the FERC issued an order holding
that Tennessee Gas Pipeline Company may not bill new take-or-pay costs to
Columbia Transmission. On August 6, 1996, Tennessee filed tariff sheets to
comply with that order. No requests for a rehearing of that order were filed,
thereby concluding this proceeding with respect to Columbia Transmission.

                 B. Direct Billing of Past Period Production and
Production-Related Costs

                 Columbia Gas Transmission Corp. v. FERC, C.A. No. 94-1727 (U.S.
Ct. of App., D.C. Circuit). On February 9, 1990, the U.S. Court of Appeals for
the District of Columbia Circuit issued its opinion finding that the FERC's
orders authorizing five of Columbia Transmission's upstream pipeline suppliers
to directly bill past period production related costs (Order Nos. 94 and 473) to
customers allocated based upon past period purchases violate the filed rate
doctrine and the rule against retroactive ratemaking. Therefore, the court
struck the orders authorizing direct billing and remanded the issue to the FERC
for further proceedings. On October 9, 1990, the U.S. Supreme Court denied
certiorari.

                 Columbia Transmission agreed to settlements with four of its
pipeline suppliers, which were initially approved by FERC orders issued February
11, 1993. However, by orders issued January 12, 1994, the FERC granted requests
for rehearing by Columbia Transmission's customers and rejected the settlements
because the rate recovery of the settlement payments to Columbia Transmission's
pipeline suppliers was barred by Columbia Transmission's 1985 PGA Settlement.
The same orders directed the pipeline suppliers to refund all principal Order
Nos. 94/473 direct billed amounts collected from Columbia Transmission, but
provided that no interest would be required on such refunds. FERC issued a
similar ruling with regard to a settlement with the fifth pipeline supplier,
Transcontinental Gas Pipeline Corporation ("Transco"), on February 13, 1995.
Columbia Transmission and its pipeline suppliers filed petitions for review of
the FERC's orders with the D.C. Court of Appeals.

                 In late 1995 and early 1996 new settlements were reached with
all pipeline suppliers except Transco, whereby the pipeline suppliers refunded
amounts previously billed to Columbia Transmission, plus interest. On September
10, 1996, the D.C. Circuit issued a decision which reversed a prior
determination by the FERC and directed that a previous settlement reached
between Columbia Transmission and Transco be approved. Reserves adequate in the
opinion of management were established in the third quarter of 1996 by Columbia
Transmission to reflect the court's decision. The matter was remanded to the
FERC, which issued its order on remand on January 21, 1997, approving the
settlement with Transco and ordering Columbia Transmission to refund to Transco
all amounts Transco had refunded to Columbia Transmission in excess of the
refunds required by the settlement, plus interest, within fifteen days of the
order.

                 On January 30, 1997, Columbia Transmission filed with the FERC
a request for rehearing and a request for deferral of action pending action by
the Bankruptcy Court. On the same day, Columbia Transmission filed with the
Bankruptcy Court its objection to Transco's bankruptcy claim for the refunds
paid to Columbia Transmission. Approximately $7 million (plus interest) is at
issue with Transco in this matter.

                 On February 28, 1997, the FERC granted Columbia Transmission's
request for rehearing, relieving it of the obligation to refund amounts to
Transco within 15 days of the order and requiring Columbia Transmission to
report any action taken by the Bankruptcy Court.

                 C.  Transportation Costs Recovery Adjustment (TCRA)

                 Columbia Gas Transmission Corp., Docket No. RP95-196 and UGI
Utilities, Inc. v. Columbia Gulf Transmission Co. and Columbia Gas Transmission
Corp., Docket No. RP95-392. On March 30, 1995, the FERC accepted Columbia
Transmission's semi-annual filing to recover operational and stranded Account
No. 858 costs (including exit fees) paid to upstream pipelines, subject to
refund and conditions. However, Columbia Transmission was required to further
document and support why it was appropriate to recover an additional $39 million
of costs paid to Columbia Gulf Transmission Company ("Columbia Gulf"). An April
17, 1995 settlement approved by the FERC on June 15, 1995, in


                                       10
<PAGE>   11
ITEM 3.  LEGAL PROCEEDINGS (Continued)

Docket No. GP94-2, resolved all issues in this docket except Columbia
Transmission's recovery of costs paid to Columbia Gulf under the T-1 Rate
Schedule.

                 On April 2, 1996, the FERC issued an order ruling generally
that Columbia Gulf could bill the costs to Columbia Transmission and that
Columbia Transmission could recover the costs from its customers, and denying
all protests and denying UGI's request for a rehearing. The FERC did, however,
make recovery of operation and maintenance costs (approximately $19 million)
subject to the FERC's next audit of Columbia Gulf, and directed its staff to
audit Columbia Gulf's non-environmental costs to assure that they were
appropriately billed to Columbia Transmission. The FERC also established hearing
procedures concerning whether Columbia Gulf's environmental costs (approximately
$20 million) were prudently incurred. Two parties filed testimony on September
30, 1996 advocating, among other things, disallowance of recovery of certain
costs by Columbia Transmission. A hearing date is currently set for late March
1997.

 III.            Environmental

                     A. In re Marcor Environmental, Inc. v. Columbia Gas
Transmission Corp., (U.S. EPA Reg. III, No. CAA-III-055) (September 30, 1994).
As reported in the Quarterly Report on Form 10-Q for the second quarter of 1996,
Marcor has agreed to indemnify Columbia Transmission for all liabilities arising
from the complaint. Settlement was reached between EPA Region III and the
parties for a civil penalty of $40,000. The settlement was filed with the Chief
Administrative Law Judge on May 21, 1996. Therefore, this matter is concluded
with respect to Columbia Transmission.

                     B. Columbia Gas Transmission Corp. v. Aetna Casualty &
Surety Co., et al., C.A. No. 94-C-454 (Kanawha (W.Va.) Cir. Ct. March 14, 1994).
Columbia Transmission filed a complaint in West Virginia state court seeking
coverage from various insurers under various insurance policies for
environmental cleanup costs. These costs are discussed more fully in the
Management's Discussion and Analysis of Financial Condition and Results of
Operations section of this Report. All insurers have responded to the complaint
denying such claims. The case is currently stayed under the evergreen provision
of the agreed scheduling order entered by the state court on November 29, 1995,
in order to allow informal discussions among the parties to the litigation. The
parties have also entered into an agreed order concerning a special discovery
master which was entered by the court.

                     C. Columbia Gulf Transmission Co. v. Aetna Casualty &
Surety Co., et al., C.A. No. 95-C-177 (Kanawha (W.Va.) Cir. Ct. January 19,
1995). Columbia Gulf filed a complaint in West Virginia state court seeking
coverage from various insurers under various insurance policies for
environmental cleanup costs. These costs are discussed more fully in the
Management's Discussion and Analysis of Financial Condition and Results of
Operations section of this Report. All insurers have responded to the complaint
denying such claims. The case is currently stayed under the evergreen provision
of the agreed scheduling order entered by the state court on December 1, 1995,
in order to allow informal discussions among the parties to the litigation. The
parties have also entered into an agreed order concerning a special discovery
master which was entered by the court.

IV.              Other

                     A. Canada Southern Petroleum Ltd. v. Columbia Gas
Development of Canada Ltd. (C.A. No. 9001-03466, Court of Queen's Bench,
Alberta, Canada, filed March 7, 1990). The plaintiff asserts, among other
things, that the defendant working interest owners, including Columbia Gas
Development of Canada Ltd. ("Columbia Canada") and various Amoco affiliates,
breached an alleged fiduciary duty to ensure the earliest feasible marketing of
gas from the Kotaneelee field (Yukon Territory, Canada). The plaintiff seeks,
among other remedies, the return of the defendants' interests in the Kotaneelee
field to the plaintiff, a declaration that such interests are held in trust for
the plaintiff and an order requiring the defendants to promptly market
Kotaneelee gas or assessing damages.

                     In November 1993, the plaintiff amended its Amended
Statement of Claim to include allegations that the balance in the Carried
Interest Account (an account for operating costs which are recoverable by
working interest owners) which is in excess of the balance as of November 1988
should be reduced to zero. Columbia, on behalf of Columbia Canada, consented to
the amendment in consideration of the plaintiff's acknowledgment that some $63
million was properly charged to the account. However, Columbia and Columbia
Canada continue to dispute the claim to the extent that the claim challenges
expenditures incurred since November 1988, including expenditures made after
Columbia Canada was sold to Anderson Exploration Ltd. ("Anderson") effective
December 31, 1991.


                                       11
<PAGE>   12
ITEM 3.  LEGAL PROCEEDINGS (Continued)

                     A trial commenced in the third quarter of 1996 in the Court
of Queen's Bench, and has since been adjourned while the plaintiff sought to
have Amoco's counsel removed based upon a conflict of interest. At a hearing on
the matter, the court ruled against the plaintiff, and a subsequent appeal by
the plaintiff was dismissed. Due to the complex nature of the litigation,
Columbia cannot predict the length of the trial. Management continues to believe
that its defenses are meritorious, and that the risk of any material liability
to Columbia is de minimis.

                     Pursuant to an Indemnification Agreement regarding the
Kotaneelee Litigation entered into when Columbia Canada was sold to Anderson,
Columbia agreed to indemnify and hold Anderson harmless for losses due to this
litigation arising out of actions occurring prior to December 31, 1991. An
escrow account now funded by a letter of credit in the amount of approximately
$71,690,000 (Cdn) provides security for the indemnification obligation.

                     B. LG&E Natural Marketing Inc. v. Columbia Gulf
Transmission Co. and Columbia Gas Transmission Corp., Case No. 1:96CV02238 (U.S.
Dist. Ct. for the District of Columbia) and C.A. No. 96-CA07745 (Sup. Ct. of the
District of Columbia). On September 27, 1996, LG&E Natural Marketing Inc.
("LG&E") filed two similar complaints in the United States District Court for
the District of Columbia and in the Superior Court of the District of Columbia
(Civil Division). The complaints alleged that Columbia Transmission and Columbia
Gulf breached purported obligations to make certain pipeline transportation
capacity available to LG&E. The complaints sought $10 million under each of a
number of different counts and punitive and treble damages under some of them.
Both cases were dismissed without prejudice. The parties are discussing the
possibility of a mutually satisfactory business arrangement to resolve this
matter. Management believes that the complaints' claims, should they be
reasserted, do not represent a material exposure to Columbia.

                     C. Cathodic Protection. In September 1995, the management
of Commonwealth Gas Services, Inc. ("Commonwealth") advised the Staff of the
Virginia State Corporation Commission that there had been deficiencies in
Commonwealth's cathodically protected pipeline distribution system in its
Northern Operating Area in Virginia. Following several months of informal
investigation, on March 1, 1996 the Commission issued a subpoena for
Commonwealth to produce documents related to its cathodic protection program in
the Northern Operating Area. Commonwealth complied with the subpoena, and
continues to provide monthly reports to the Commission updating the status of
remedial work in the Northern Operating Area and annual test station monitoring.
Given the early status of this investigation, Columbia is unable to determine at
this time the likelihood or magnitude of any penalties that might be assessed.


ITEM 4.          SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None

                                     PART II

ITEM 5.        MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
                 MATTERS

The common stock of Columbia is traded on the New York Stock Exchange under the
ticker symbol CG and abbreviated as either ColumGas or ColGs in trading reports.
The number of shareholders of record on January 31,1997, was approximately
40,766 and the stock closed at $64.875, as reflected in the New York Stock
Exchange Composite Transactions as reported by The Wall Street Journal. On
February 19, 1997, Columbia declared a quarterly dividend of $0.15 per share for
the first quarter of 1997, payable on or about March 14, 1997, to holders of
record on March 3, 1997.

See Item 7 on page 20 for additional information regarding Columbia's common
stock prices and dividends.


                                       12
<PAGE>   13
ITEM 6.          SELECTED FINANCIAL DATA


                             SELECTED FINANCIAL DATA

                 The Columbia Gas System, Inc. and Subsidiaries

<TABLE>
<CAPTION>
($ in millions except per share amounts)                1996        1995*         1994*         1993*         1992*         1991*
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                  <C>          <C>           <C>           <C>           <C>           <C>    
  INCOME STATEMENT DATA ($)
   Total operating revenues                          3,354.0      2,635.2       2,747.1       3,313.8       2,859.2       2,463.7
   Products purchased                                1,481.1        820.6         984.2       1,577.7       1,236.9       1,056.5
   Earnings (Loss) on common stock before
      extraordinary item and accounting changes        221.6       (432.3)        246.2         152.2          90.9        (794.8)
   Earnings (Loss) on common stock                     221.6       (360.7)        240.6         152.2          51.2        (694.4)
---------------------------------------------------------------------------------------------------------------------------------
PER SHARE DATA
   Earnings (Loss) per common share ($):
      Before extraordinary item and
         accounting changes                             4.12        (8.57)         4.87          3.01          1.79        (15.72)
      Earnings (Loss) on common stock                   4.12        (7.15)         4.76          3.01          1.01        (13.74)
   Dividends:
      Per share ($)                                     0.60           --            --            --            --          1.16
      Payout ratio (%)                                  14.6          N/A           N/A           N/A           N/A           N/A
   Average common shares outstanding (000)            53,782       50,468        50,560        50,559        50,559        50,537
---------------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET DATA ($)
   Capitalization including debt
      subject to Chapter 11:
         Common stock equity                         1,553.6      1,114.0       1,468.0       1,227.3       1,075.1       1,006.9
         Preferred stock                                  --        399.9            --            --            --            --
         Long-term debt                              2,003.8      2,004.5           4.3           4.8           5.4           6.1
         Short-term debt                                 N/A          N/A            --            --            --           N/A
         Current maturities of long-term debt            0.8          0.5           1.2           1.3           1.4           2.9
         Debt subject to Chapter 11                       --           --       2,317.1       2,317.1       2,317.1       2,317.1
         Total                                       3,558.2      3,518.9       3,790.6       3,550.5       3,399.0       3,333.0
   Total assets                                      6,004.6      6,057.0       7,164.9       6,957.9       6,505.9       6,332.2
---------------------------------------------------------------------------------------------------------------------------------
OTHER FINANCIAL DATA
   Capitalization ratio (%) (including
      current maturities**):
         Common stock equity                            43.7         31.7          38.7          34.6          31.6          30.2
         Preferred stock                                  --         11.4            --            --            --            --
         Debt                                           56.3         56.9          61.3          65.4          68.4          69.8
   Capital expenditures ($)                            314.8        421.8         447.2         361.3         299.7         381.9
   Net cash from operations ($)                        462.7       (807.4)        572.8         850.4         765.4         531.6
   Book value per common share ($)                     28.11        22.07         29.03         24.27         21.26         19.92
   Return on average common equity
      before extraordinary item
      and accounting changes (%)                        16.6        (33.5)         18.3          13.2           8.7           N/A
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>

N/A - Not applicable

 *Reference is made to Note 2 of Notes to Consolidated Financial Statements. Due
to the bankruptcy filings, interest expense of approximately $230 million, $210
million, $204 million and $86 million was not recorded in 1994, 1993, 1992 and
1991, respectively. Interest expense of $982.9 million including write-off of
unamortized discounts on debentures, was recorded in the fourth quarter of 1995.

**Prior to 1991, Columbia made extensive use of variable rate debt since the
associated cost was normally less than senior long-term debt. Inclusion of the
short-term debt in years prior to 1991 makes those historical ratios more
meaningful.


                                       13
<PAGE>   14
ITEM 6.  SELECTED FINANCIAL DATA (Continued)


                             SELECTED FINANCIAL DATA

                 The Columbia Gas System, Inc. and Subsidiaries

<TABLE>
<CAPTION>
($ in millions except per share amounts)                                   1990         1989         1988         1987         1986
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>          <C>          <C>          <C>          <C>    
INCOME STATEMENT DATA ($)
   Total operating revenues                                             2,346.7      3,189.3      3,157.5      2,855.7      3,407.7
   Products purchased                                                     846.8      1,669.0      1,822.3      1,534.2      2,002.9
   Earnings (Loss) on common stock before
      extraordinary item and accounting changes                           104.7        145.8        119.0        111.3         99.4
   Earnings (Loss) on common stock                                        104.7        145.8        111.1        100.5         75.3
-----------------------------------------------------------------------------------------------------------------------------------
PER SHARE DATA
   Earnings (Loss) per common share ($):
      Before extraordinary item and
         accounting changes                                                2.21         3.21         2.46         2.30         2.12
      Earnings (Loss) on common stock                                      2.21         3.21         2.46         2.30         1.82
   Dividends:
      Per share ($)                                                        2.20         2.00         2.29         3.18         3.18
      Payout ratio (%)                                                     99.5         62.3         93.3        138.3        174.7
   Average common shares outstanding (000)                               47,316       45,494       45,190       43,763       41,436
-----------------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET DATA ($)
   Capitalization including debt subject to Chapter 11:
         Common stock equity                                            1,757.8      1,620.3      1,552.6      1,523.7      1,448.7
         Preferred stock                                                     --           --           --        110.0        115.0
         Long-term debt                                                 1,428.7      1,196.0      1,038.4      1,438.0      1,378.5
         Short-term debt                                                  735.5        634.2        697.1        327.5        393.4
         Current maturities of long-term debt                              35.2         47.2         52.7         69.6        432.5
         Debt subject to Chapter 11                                          --           --           --           --           --
         Total                                                          3,957.2      3,497.7      3,340.8      3,468.8      3,768.1
   Total assets                                                         6,196.3      5,878.4      5,641.0      5,440.9      5,590.2
-----------------------------------------------------------------------------------------------------------------------------------
OTHER FINANCIAL DATA
   Capitalization ratio (%) (including short-term debt and current
      maturities**):
         Common stock equity                                               44.4         46.3         46.5         43.9         38.4
         Preferred stock                                                     --           --           --          3.2          3.1
         Debt                                                              55.6         53.7         53.5         52.9         58.5
   Capital expenditures ($)                                               629.6        473.5        307.9        298.8        232.3
   Net cash from operations ($)                                           420.1        400.5        429.4        702.0        550.5
   Book value per common share ($)                                        34.83        35.50        34.18        34.08        34.06
   Return on average common equity
      before extraordinary item
      and accounting changes (%)                                            6.2          9.2          7.7          7.5          6.9
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

N/A - Not applicable

 *Reference is made to Note 2 of Notes to Consolidated Financial Statements. Due
to the bankruptcy filings, interest expense of approximately $230 million, $210
million, $204 million and $86 million was not recorded in 1994, 1993, 1992 and
1991, respectively. Interest expense of $982.9 million including write-off of
unamortized discounts on debentures, was recorded in the fourth quarter of 1995.

**Prior to its Chapter 11 filing, Columbia made extensive use of variable rate
debt since the associated cost was normally less than senior long-term debt.
Inclusion of the short-term debt in years prior to 1991 makes those historical
ratios more meaningful.


                                       14
<PAGE>   15
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
         RESULTS OF OPERATIONS



<TABLE>
<CAPTION>
Index                                           Page
----------------------------------------------------
<S>                                             <C>
Consolidated Review......................        15
Liquidity and Capital Resources..........        17
Transmission and Storage Operations......        21
Distribution Operations..................        27
Exploration and Production Operations....        33
Marketing, Propane and Power Generation..        36
Bankruptcy Matters.......................        39
----------------------------------------------------
</TABLE>

Management's Discussion and Analysis contains "forward-looking statements"
within the meaning of Section 27A of the Securities Act of 1933 and Section 21E
of the Securities Exchange Act of 1934. Shareholders and prospective
shareholders should understand that several factors govern whether any
forward-looking statement contained herein will be or can be achieved. Any one
of those factors could cause actual results to differ materially from those
projected herein. These forward-looking statements include Columbia's plans,
objectives and expected performance, expenditures and recovery of expenditures
through rates. These forward-looking statements are based on assumptions that
management believes to be reasonable, however, there can be no assurance that
actual results will not differ materially. Realization of Columbia's objectives
and expected performance is subject to a wide range of risks and can be
adversely affected by, among other things, competition, weather, regulatory and
legislative changes as well as changes in general economic and capital market
conditions, many of which are beyond the control of Columbia.

                               CONSOLIDATED REVIEW

Net Income (Loss)

Columbia's 1996 net income was $221.6 million, or $4.12 per share, compared to a
net loss of $360.7 million, or $7.15 per share, last year which included pre-tax
interest expense of $983 million on prepetition debt that was recorded at
Columbia's emergence from bankruptcy in November 1995.

After adjusting for unusual items, net income for 1996 was $251.7 million, or
$4.68 per share, up $98.4 million, or more than 64%, over 1995's adjusted
results. Contributing to this improvement was the after-tax effect of nearly $45
million for higher rates for the regulated subsidiaries, $24 million
attributable to higher prices for gas production and $17 million resulting from
colder weather experienced primarily in early-1996. Also improving results were
lower operation and maintenance expenses, net of restructuring charges,
reflecting the efficiencies gained through recently implemented restructuring
initiatives.

                      Unusual and Bankruptcy Related Items
                         After-tax effect on Net Income
                                  (in millions)

<TABLE>
<CAPTION>
                                                                      Twelve Months
                                                                    Ended December 31,
                                                                      1996        1995
                                                                   -------     -------
<S>                                                                <C>         <C>     
Reported Net Income (Loss)                                         $ 221.6     $(360.7)
Less (plus):
    Bankruptcy related issues
        Entries recorded at emergence, primarily interest costs         --      (649.4)
        Interest costs on prepetition debt not recorded                 --       158.0
        Professional fees and related expenses                          --       (26.8)
    Adoption of SFAS No. 71                                             --        71.6
    Sale of Columbia Development                                       5.6       (54.8)
    Restructuring-related costs                                      (35.7)       (3.8)
    Other                                                               --        (8.8)
                                                                   -------     -------
       Total adjustments                                             (30.1)     (514.0)
                                                                   -------     -------
Net Income after adjusting for unusual and bankruptcy items        $ 251.7     $ 153.3
                                                                   =======     =======
</TABLE>


                                       15
<PAGE>   16
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF OPERATIONS (Continued)

Unusual items in 1996 included $35.7 million for the after-tax effect of
restructuring costs, primarily for severance expense, that were incurred to
improve customer service and operating efficiencies. A second unusual item in
1996 was a $5.6 million improvement to net income for a favorable adjustment
from the sale of Columbia Gas Development Corporation (Columbia Development),
Columbia's southwest gas and oil subsidiary, that was sold effective year end
1995.

Adjustments for 1995 unusual items included after-tax expense of $518.2 million
related to bankruptcy issues, primarily for interest expense to settle
prepetition obligations; an improvement to net income of $71.6 million for the
readoption of an accounting standard pertaining to the accounting in a rate
regulated environment, Statement of Financial Accounting Standards No. 71,
"Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71); $54.8
million to record the estimated after-tax loss on the sale of Columbia
Development; $3.8 million after-tax costs for restructuring activities and
after-tax expense of $8.8 million for miscellaneous other unusual items.

Revenues

Operating revenues for 1996 of $3,354 million, increased $718.8 million over
1995, reflecting, among other things, additional sales by Columbia Energy
Services Corporation, Columbia's marketing affiliate, and the distribution
subsidiaries. Also contributing to increased revenues were sharply higher gas
prices that increased both the gas commodity portion of the rates for the
distribution subsidiaries and prices received for gas production, as well as the
effect of colder weather experienced primarily in early 1996. In addition,
higher base rates in effect for the regulated subsidiaries provided an increase
to revenues of $68.7 million. In 1996, $13.9 million of the increase in revenues
over 1995 was due to surcharges that were offset in operating expense and had no
effect on income. Partially offsetting these improvements was the effect of the
sale of Columbia Development which had $96.1 million of revenues in 1995 and a
$12.2 million non-recurring increase in 1995 from exit fee payments received by
Columbia Gulf Transmission Company (Columbia Gulf).

In 1995 operating revenues decreased $111.9 million from 1994 due to lower
natural gas prices which reduced revenues for the distribution segment and
decreased the price received for gas produced. The decrease was partially offset
by both higher revenues from additional retail sales and higher rates in effect
for the non-gas portion of the sales rate for the distribution segment.
Improving 1995 operating revenues were the exit fee payments received by
Columbia Gulf and $10.3 million in surcharges that were offset in operating
expense.

Expenses

Operating expenses in 1996 of $2,875.8 million, increased $630.8 million over
1995. The higher expenses primarily reflected an increase of $660.5 million in
products purchased caused by additional volumes purchased to meet increased
sales requirements and higher gas prices. Also increasing operating expense was
$22.6 million higher operation and maintenance expense which included $54.9
million restructuring costs in 1996 and $5.8 million in 1995, expense of
approximately $13.9 million for surcharges that are offset in revenues, as
mentioned above. Prior year's expenses included $39.1 million of expenses
associated with Columbia Development's operations. After adjusting for
restructuring charges, operation and maintenance expenses were down by
approximately $30 million for 1996. Depreciation and depletion expense decreased
$54.8 million as a result of reduced depletable plant due to the sale of
Columbia Development and a lower depletion rate attributable to higher natural
gas prices, partially offset by additional plant in service and higher
depreciation rates for the regulated subsidiaries.

In 1995, operating expenses of $2,245 million were down $118 million from 1994
due largely to lower cost of gas for resale. Despite additional purchases
necessary to meet increased sales requirements, the cost of gas purchased in
1995 was lower than the year earlier by $163.6 million, reflecting lower average
prices. In 1995, operating and maintenance expense was $35.2 million higher than
the year earlier reflecting generally higher costs. Mitigating this increase was
the effect of a $19.1 million environmental reserve addition recorded in 1994.
Depreciation and depletion expense was also up $8.3 million due to additional
plant in service. Operating expense included $10.3 million that was offset by
revenue surcharges mentioned above.


                                       16
<PAGE>   17
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF OPERATIONS (Continued)

Other Income (Deductions)

<TABLE>
<CAPTION>
                                         Twelve Months Ended December 31,
 (in millions)                              1996        1995         1994
                                        --------    --------     --------
<S>                                     <C>         <C>          <C>     
Interest income and other, net          $   26.1    $   (58.2)   $   35.2
Interest expense and related charges      (166.8)      (988.4)      (14.8)
Reorganization items, net                     --         13.4       (12.3)
                                        --------    ---------    --------
Total Other Income (Deductions)         $ (140.7)   $(1,033.2)   $    8.1
                                        ========    =========    ========
</TABLE>

For the twelve months ended December 31, 1996, Other Income (Deductions) reduced
income $140.7 million, compared to a decrease to income of $1,033.2 million in
1995. Interest income and other, net of $26.1 million in 1996 primarily
reflected an adjustment of $8.6 million recorded in the second quarter of 1996
for the 1995 sale of Columbia Development; $5.6 million of interest earned on
certain tax issues, $3.3 million of interest income on temporary cash
investments and a $1.8 million gain on the sale of Columbia Gulf's interests in
the Overthrust pipeline partnership. Interest expense and related charges in
1996 reflected $140.4 million of interest expense on long-term debt and $11.7
million of interest expense on short-term debt obligations. Also included in
1996 interest expense was $3.9 million of interest on rate refunds recorded by
the rate regulated subsidiaries.

Other Income (Deductions) reduced income in 1995 by $1,033.2 million, whereas in
1994, income was improved $8.1 million. Interest expense and related charges for
1995 was $973.6 million higher than 1994 due primarily to bankruptcy-related
interest costs on prepetition debt obligations of $983 million recorded at
emergence. A $15.8 million reduction to a reserve for interest charges was
recorded in 1994 for an IRS settlement that was largely offset by $14.7 million
of interest expense associated with producer claims recorded in the same year.
The $93.4 million decrease for Interest income and other, net primarily
reflected an estimated loss of $77.8 million recorded in 1995 for the sale of
Columbia Development and an improvement of $21 million in 1994 for the reversal
of a reserve for carrying charges on exchange gas. Reorganization items, net
increased $25.7 million from the prior year due to $40 million recorded for the
principal portion of the producer claim reserve in 1994 and $30.1 million for
higher interest earned on cash accumulated during the Chapter 11 proceedings.
These improvements were offset by $44 million for bankruptcy-related emergence
adjustments as well as additional expense for professional fees and related
charges.

Income Taxes

Income tax expense in 1996 decreased income $115.9 million, whereas in 1995 when
a pre-tax loss was recorded, a tax benefit of $210.7 million was reflected. Tax
expense was $146 million in 1994. These changes between years were caused
principally by changes in pre-tax book income. (See Note 7 in Notes to
Consolidated Financial Statements for additional information.)

Extraordinary Items

In 1995, Columbia recorded an extraordinary after-tax gain of $71.6 million for
the cumulative adjustment for the reapplication of SFAS No. 71 for Columbia
Transmission and Columbia Gulf. The impact of the reapplication resulted in the
recognition of regulatory assets for certain costs previously expensed which are
expected to be recovered in rates, mainly environmental and postemployment
benefit costs, and recording revenues and expenses in a manner to reflect the
ratemaking process. Management believes that cost of service rate concepts will
continue to be applicable to Columbia's Federal Energy Regulatory Commission
(FERC) regulated transmission subsidiaries for the foreseeable future.

                         LIQUIDITY AND CAPITAL RESOURCES

Cash From Operations

A significant portion of Columbia's operations is subject to seasonal
fluctuations in cash flow. During the heating season, which is essentially from
November through March, cash receipts from sales and transportation services
typically exceed cash requirements. Conversely during the remainder of the year
cash on hand, together with external financing as needed, is used to purchase
gas to place in storage for heating season deliveries, make capital improvements
in plant, perform necessary maintenance of the facilities, and expand service
into new areas.

For the year ended December 31, 1996, net cash from operations was $462.7
million whereas in 1995, a cash deficit of $807.4 million was reported due to
cash paid to producers and other creditors on emergence from bankruptcy.
Included in the 1995 cash from operations was approximately $1.4 billion of cash
paid on emergence to satisfy allowed claims filed against Columbia and Columbia
Transmission. After adjusting the 1995 deficit for these emergence payments,


                                       17
<PAGE>   18
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF OPERATIONS (Continued)

cash from operations in 1996 decreased $179.9 million from 1995. Reducing cash
was a lag in the recovery of gas costs by the distribution subsidiaries in the
current period, together with increased prepayments and the effect of a higher
average cost of gas placed in storage. The lag in recovering gas costs resulted
from the rise in prices during 1996 that exceeded the distribution subsidiaries'
current recovery levels. These higher costs will be recovered over the next
several months through future adjustments to the commodity portion of rates as
provided for under the regulatory process. Partially offsetting this decrease
was a working capital improvement of $271.5 million for income tax refunds that
resulted from the filing of Columbia's 1995 Federal Income Tax return that
included a net operating loss carryback claim to recover income taxes. Cash also
improved as a result of the favorable effect of colder weather that increased
sales for the distribution subsidiaries, as well as higher base rates in effect
for the regulated subsidiaries.

After adjusting the 1995 deficit for emergence issues, net cash from operations
was $73.1 million higher than 1994, primarily reflecting payments made in 1994
for Order 500/528 refunds. Cash from operations for both 1995 and 1994 was
affected by supplier refunds and payments made by Columbia Transmission.

Financing Activities

Columbia satisfies its liquidity requirements through internally generated funds
and the use of its $1 billion unsecured bank revolving credit facility (Credit
Facility). Columbia also may pursue obtaining additional short-term financing
through the use of bid notes and the establishment of a commercial paper
program.

Upon emergence from bankruptcy, Columbia issued $2 billion of debentures and
approximately $200 million each of 5.22% Convertible Preferred Stock, Series B
(Series B - DECS) and 7.89% Redeemable Preferred Stock, Series A (Series A -
Preferred Stock) to holders of Columbia's pre-bankruptcy debt securities. The
$2.4 billion distribution of securities and cash from bank borrowings under the
Credit Facility as discussed below, and cash on hand were used to settle claims
in accordance with approved plans of reorganization for Columbia and Columbia
Transmission. Maturities of the new debentures ranged from 5 to 30 years with an
average interest cost of approximately 7.03%. In February 1996, Columbia
redeemed the Series B - DECS and Series A - Preferred Stock as allowed under the
terms of Columbia's approved plan of reorganization. Permanent funding for the
preferred stock redemption was provided by $191 million received in April 1996,
from the sale of Columbia Development and approximately $240 million received
from the issuance of new common stock under a shelf registration statement, as
more fully described below.

Columbia's $1 billion Credit Facility provides for scheduled quarterly
reductions of $25 million of the aggregate committed amount starting December
31, 1997, that will reduce the Credit Facility commitments to $700 million by
September 30, 2000. The Credit Facility also provides for the issuance of up to
$150 million of letters of credit. As of December 31, 1996, Columbia had $250
million of borrowings and approximately $87 million of letters of credit
outstanding under the Credit Facility.

Interest rates on borrowings are based upon the London Interbank Offered Rate,
Certificate of Deposit rates or other short-term interest rates. Columbia is
required to pay a facility fee on the commitment amount at a rate based on
Columbia's public debt rating. The facility fee rate, as of December 31, 1996,
is 0.14%. Such rate would be reduced to 0.11% were Columbia to achieve a BBB+ or
Baa1 rating from Standard & Poor's or Moody's Investors Service, respectively.

Columbia has an effective shelf registration statement on file with the U. S.
Securities and Exchange Commission for the issuance of up to $1 billion in
aggregate of debentures, common stock or preferred stock in one or more series.
In March 1996, Columbia issued 5,750,000 shares of common stock under the shelf
registration and used the proceeds to reduce borrowings incurred under the
Credit Facility. No further issuances under the remaining $750 million are
scheduled at this time.


                                       18
<PAGE>   19
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF OPERATIONS (Continued)



Capital Expenditures

The table below reflects actual capital expenditures by segment for 1995 and
1996 and an estimate for 1997:

<TABLE>
<CAPTION>
(in millions)                              1997     1996    1995
----------------------------------------------------------------
<S>                                        <C>      <C>     <C> 
Transmission and Storage                   $269     $143    $172
Distribution                                160      148     152
Exploration and Production                   39*      12      87
Marketing, Propane and Power Generation       8        6       7
Corporate                                    14        6       4
----------------------------------------------------------------
Total                                      $490     $315    $422
----------------------------------------------------------------
</TABLE>

*   Does not reflect approximately $27 million for gathering facilities that
    Columbia Transmission abandoned and transferred to Columbia Natural
    Resources, Inc.

Columbia's 1996 capital expenditures were $315 million, a decrease of $107
million from 1995. The decrease primarily reflected lower expenditures for
exploration and production due to the sale of Columbia Development effective
December 31, 1995. The largest portion of the transmission and storage segment's
investments is made to assure the safety and reliability of the pipelines.
Distribution subsidiaries' program included investments to extend service to new
areas and develop future markets, as well as expenditures required to ensure
safe and reliable service and improved service.

Capital expenditures for 1997 are expected to increase $175 million to $490
million. This increase reflects $117 million of additional expenditures for
Columbia Transmission's market expansion program and higher expenditures for the
exploration and production segment as a result of the increased drilling
activity by Columbia Natural Resources, Inc. (Columbia Resources). Ongoing
replacement and upgrading of the distribution and pipeline facilities of
approximately $188 million will represent a significant portion of the 1997
program.

All discretionary capital expenditures are subject to Columbia's value added
approach (CVA), that determines whether the anticipated return on a business
activity or project exceeds its risk adjusted capital cost. The CVA process was
initiated to encourage employees to think in terms of value enhancement.

Restructuring Activities

In 1996, $60.9 million (pre-tax) of expense was recorded to reflect
reengineering-related costs, primarily for severance and benefits. Partially
offsetting this expense was a $6 million gain on the sale of the Wilmington,
Delaware, headquarters building. This reengineering initiative, called Project
Phoenix, began in 1995 to streamline operations and make them more efficient and
cost-competitive. As these reengineering activities continue into 1997,
additional expense will be incurred. The beneficial effect of any efficiencies
gained will be realized through improved profitability of Columbia's operations
and reduced rates being charged to customers of the regulated subsidiaries.

As indicated in the results of operations, Columbia is beginning to realize
lower operation and maintenance costs as a result of implementing these
reengineering initiatives in its various operations. It is anticipated that the
favorable effect of these initiatives will continue in the future as additional
phases of the program are implemented. Once the project is fully implemented,
which is expected by the end of 1997, the total number of employees System-wide
is anticipated to decrease by approximately 10% from the year-end 1995 level of
nearly ten thousand.

Reporting of Segment Results

Effective with this report the transmission segment has been renamed
Transmission and Storage Operations and now includes the results of Columbia LNG
Corporation (Columbia LNG) since its primary line of business is storage
services which are regulated by the FERC. Columbia LNG is a partner in Cove
Point LNG Limited Partnership (Cove Point LNG) which recently began commercial
operation of one of the largest natural gas peaking and storage facilities in
the United States located near Cove Point, Maryland. The facility liquefies
natural gas to meet winter peak day requirements of utilities and other large
gas users. Previously the results of Columbia LNG were included in Other Energy
Operations which has been renamed Marketing, Propane and Power Generation to
reflect the diverse energy-related operations of


                                       19
<PAGE>   20
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF OPERATIONS (Continued)

this segment of Columbia's business. Columbia's oil and gas segment has been
renamed Exploration and Production Operations.

                        COMMON STOCK PRICES AND DIVIDENDS


<TABLE>
<CAPTION>
                         Market Price
                 ---------------------------       Quarterly
Quarter Ended     High       Low      Close     Dividends Paid
--------------------------------------------------------------
<S>              <C>        <C>       <C>       <C>
                   $          $         $             $
1996
December 31      66 1/4     56        63 5/8         .15
September 30     59 5/8     51        56             .15
June 30          52 1/8     43 3/4    51 7/8         .15
March 31         46 1/2     42 1/4    45 7/8         .15
--------------------------------------------------------------
1995
December 31      44 1/8     36        43 7/8          --
September 30     39 3/4     31 3/8    38 5/8          --
June 30          32 7/8     28 3/4    31 3/4          --
March 31         29 3/4     23 1/8    29 5/8          --
--------------------------------------------------------------
</TABLE>


                                       20
<PAGE>   21
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF OPERATIONS (Continued)


                       TRANSMISSION AND STORAGE OPERATIONS

Marketing Initiatives

In January 1997, FERC issued a preliminary determination approving the
non-environmental portion of the expansion of Columbia Transmission's pipeline
and storage systems to serve the increasing needs of customers. Columbia
Transmission has signed 15-year agreements with 23 customers, subject to
Columbia Transmission obtaining regulatory approval of the project, for
approximately 500,000 Mcf per day (Mcf/d) of additional firm service to be
phased in over a three-year period beginning November 1, 1997. FERC approved
Columbia Transmission's request to roll the cost of the project into existing
rates rather than charge an incremental rate to the market expansion customers.
The project as approved includes a reduction to the project's initial estimated
$350 million cost to approximately $270 million, with no change in customer
service levels. The reduced cost reflects an agreement between Columbia
Transmission and Texas Eastern Transmission Corporation (Texas Eastern) under
which Texas Eastern will increase capacity on its Pennsylvania pipeline system
and provide the new capacity to Columbia Transmission. The environmental aspects
of the expansion project are pending before FERC and will be addressed in a
subsequent order. Final approval of Columbia Transmission's market expansion
application is anticipated by mid-1997.

Regulatory Matters

                       Columbia Transmission's Rate Filing

In August 1995, Columbia Transmission filed with FERC its first general rate
case since 1991. The filing requested an increase in annual revenues of
approximately $147 million and proposed to recover the net investment in
gathering and certain gas processing facilities over a period of five years.

In January 1997, the FERC administrative law judge presiding over the rate case
certified to FERC a settlement filed on November 22, 1996 by Columbia
Transmission. The settlement, which is supported by all of Columbia
Transmission's firm service customers, will resolve virtually all issues,
including rate design, cost of service, and the unbundling of gathering and
products extraction costs from Columbia Transmission's transportation rates.
Excluded from the settlement is the environmental cost recovery issue which is
scheduled to be addressed in a second phase of the proceeding. Pending the
outcome of that proceeding, Columbia Transmission will continue to collect
approximately $18 million per year, subject to refund, for environmental costs.
The certified settlement:

-    establishes an annual cost-of-service level of $614 million, which is an
     increase of $55 million (excluding $18 million for environmental cost
     recovery) for the February 1996, through January 1997 period. This will
     decrease to $602 million for the February 1997 through January 2000 period;

-    provides for a moratorium on general rate increase filings through January
     31, 2000 with certain limited exceptions;

-    provides for the sharing of profits between Columbia Transmission and its
     customers from the sale of certain amounts of storage base gas;

-    provides for the unbundling of Columbia Transmission's gathering and gas
     processing costs from transportation rates, that will be phased in
     throughout the settlement period; and

-    establishes the method by which Columbia Transmission will have the
     opportunity to recover its investment in production-area facilities,
     including the spindown of approximately 40% of Columbia Transmission's
     gathering facilities to Columbia Resources.

The certified settlement is currently pending FERC review and approval, which is
anticipated in 1997.

       Recovery of Columbia Gulf's Pre-November 1994 Transportation Costs

On March 1, 1995, Columbia Transmission filed with FERC to recover $69 million
of annual projected transportation costs and $39 million of unrecovered
transportation costs that were billed to Columbia Transmission by Columbia Gulf.
Several parties filed protests with FERC regarding the Columbia Gulf charges.
FERC subsequently ruled that approximately $19 million of the Columbia Gulf
charges were recoverable by Columbia Transmission, subject to a general FERC
audit, which is underway. The remaining $20 million of costs are associated with
environmental issues. FERC scheduled a hearing for the first quarter of 1997
concerning the recovery of such environmental costs.

Two parties filed testimony on September 30, 1996, advocating, among other
things, disallowance of recovery of certain costs by Columbia Transmission.
Responsive testimony has been filed by Columbia Transmission addressing each of
the proposed disallowances. While the outcome of the hearing is uncertain,
management believes Columbia Transmission has a valid basis for recovering these
costs. It is not expected that the outcome will have a material adverse impact
on Columbia's financial statements.


                                       21
<PAGE>   22
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
             OF OPERATIONS (Continued)

                    Columbia Gulf Transmission's Rate Filing

On October 31, 1996, Columbia Gulf filed a general rate case with FERC that will
be effective May 1, 1997, subject to refund. A prior rate case settlement
required Columbia Gulf to file a new general rate case at this time. The filing
reflects a small increase of $0.9 million in the cost of service level and
addresses several rate design and cost allocation issues. On November 27, 1996,
the FERC accepted the filing subject to refund. The case has been assigned to an
administrative law judge for hearing.

                       Columbia Gulf Show Cause Proceeding

In its September 1993 order on Columbia Transmission's and Columbia Gulf's Order
No. 636 compliance filings, FERC initiated a proceeding concerning Columbia
Gulf's transportation service to Columbia Transmission. It directed Columbia
Gulf to show cause as to why it had not filed for FERC abandonment authorization
to reduce capacity on its mainline facilities. In a response to FERC in late
1993, Columbia Gulf asserted that no abandonment filing was required. During
1994 and early 1995, Columbia Transmission and Columbia Gulf responded to
information requests from FERC staff. Management continues to believe that no
abandonment filing was necessary; however, the ultimate outcome of this issue is
uncertain.

Partnership Issues

In late 1996, FERC approved a proposal by Columbia Gulf and its partners in the
Trailblazer Pipeline System, Northern Natural Gas Company and Natural Gas
Pipeline Company of America, to expand the eastern-most segment of the system.
The estimated $9 million expansion project includes installation of a
5,200-horsepower compressor to increase capacity along the 436-mile segment by
approximately 104,500 Mcf/d to a total volume of 492,000 Mcf/d. This additional
capacity is fully committed under precedent agreements for firm 10-year
contracts and should be available by August 1, 1997. This increased capacity
will allow producers to move Rocky Mountain natural gas to the Chicago area via
the Trailblazer System. The cost of the expansion is expected to lower
Trailblazer's rates by approximately 13 percent in the next rate case filing
which is anticipated to be filed in mid-1997. Columbia Gulf has a 33% ownership
interest in the Trailblazer Pipeline System.

In September 1996, Columbia Gulf recorded a gain of approximately $1.8 million
for the sale of its partnership interests in the Overthrust Pipeline System to
Questar Pipeline Company. Columbia Gulf held an 18% interest in the partnership
at the time of the sale. Columbia Gulf originally entered into the investment to
provide a gas supply source for Columbia Transmission. Under FERC Order No. 636,
Columbia Transmission discontinued its merchant function which eliminated its
need for this supply source.

Capital Expenditure Program

The transmission and storage segment's net capital expenditure program was
approximately $143 million in 1996 while its net capital expenditure program is
expected to be approximately $269 million in 1997. This included approximately
$9 million in 1996 and will include $126 million in 1997 for the market
expansion initiatives described previously. Other expenditures are for
modernizing and upgrading facilities.

Restructuring Activities

Columbia Transmission and Columbia Gulf began the Project Phoenix restructuring
project in early 1996 to streamline the business functions and improve
productivity by focusing on all processes within the transmission companies.
Implementation of key recommendations from the project began in 1996 and is
expected to be completed in stages throughout 1997.

Columbia Transmission also began the process of selling portions of its
gathering facilities as a result of FERC's Order No. 636, which requires natural
gas pipelines to unbundle their gathering costs and services from other
transportation costs. Approximately 3,000 miles of gas gathering lines will be
sold to Columbia Resources in mid-1997. Columbia Transmission has concluded an
open-bidding process for the remaining 3,600 miles of gathering lines.
Subsequent negotiations have resulted in various letters of intent for the sale
to various parties of certain of these gathering systems located in Ohio and
Pennsylvania (approximately 2,200 miles). It is likely that the facilities will
be sold before year-end 1997 to various purchasers and will result in
consolidation of some field operations and reductions in staffing levels.

As a result of these restructuring activities, expense of $24.6 million was
recorded in 1996, primarily for severance and benefits programs applicable to
staff level reductions.


                                       22
<PAGE>   23
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
             OF OPERATIONS (Continued)

Environmental Matters

Columbia's transmission subsidiaries have implemented programs to continually
review compliance with existing environmental standards. In addition, Columbia
Transmission continues to review past operational activities and to formulate
remediation programs where necessary. Columbia Transmission is currently
conducting assessment, characterization and remediation activity of specific
sites under a 1995 EPA Administrative Order by Consent (AOC).

In 1995, Columbia Transmission estimated that the cost of its environmental
program under the AOC may range between $204 million and $319 million over the
life of the program. This estimate was based on a limited amount of actual data
available and utilized a variety of assumptions, including: the number of sites
to be investigated, characterized and remediated; the location, nature and
levels of wastes that will be treated at or disposed of from each site; the
amount of time and nature of equipment required for such activities; the
appropriate remediation levels and the technology to be utilized; and the
frequency with which groundwater contamination might be discovered at sites
requiring remediation. The estimate did not include previously identified costs
for certain specific activities, aggregating approximately $50 million, for
which Columbia Transmission already had reasonable estimates.

Following an extensive review of assumptions utilized in arriving at the
estimate, management has concluded that only those site investigation,
characterization and remediation costs currently known and determinable can be
considered "probable and reasonably estimable" under Statement of Financial
Accounting Standards No. 5, "Accounting for Contingencies" (SFAS No. 5). This
conclusion was based upon the fact that the actual characterization and
remediation experience of Columbia Transmission was extremely limited and
information on environmental conditions at many of the sites or former sites of
operations was not yet available. The nature and condition of such sites varies
greatly, and any change in any of the numerous assumptions used in the estimate
may materially alter the estimated range of costs, with no assurance that actual
costs will not exceed amounts specified in the range. Columbia Transmission is
unable, at this time, to accurately estimate the time frame and potential costs
of all site screening, characterization and remediation. As Columbia
Transmission continues its program pursuant to the AOC and costs become probable
and reasonably estimable, the associated reserves will be adjusted as
appropriate. Moreover, in time, management expects that, as additional work is
performed and more facts become available, it will then be able to develop a
probable and reasonable estimate for the entire program or a major portion
thereof consistent with U. S. Securities and Exchange Commission's Staff
Accounting Bulletin No. 92, SFAS No. 5 and American Institute of Certified
Public Accountants Statement of Position 96-1.

Activities under the AOC in 1996 were focused on obtaining EPA approval to begin
the assessment and characterization of certain major facilities, some select
liquid removal points, and other select mercury measurement stations. In 1996,
the EPA authorized Columbia Transmission to begin the characterization of twelve
major facilities. Columbia Transmission expects EPA approval to begin
characterization of an additional 60 major facilities in 1997.

Columbia Transmission also continued to conduct assessment and remediation of
impacted soils at locations prior to normal construction and maintenance
activities under its EPA approved Construction and Operations Work Plan (COWP).
In 1996, Columbia Transmission conducted assessments at 216 sites and based on
these assessment results, performed remedial activities in varying degrees at
approximately 100 locations.

As a result of these 1996 activities, Columbia Transmission recorded in 1996 an
additional liability of $3.3 million in the fourth quarter and $2.5 million in
the second quarter. Actual expenditures of approximately $17 million during 1996
charged to the liability plus additions of nearly $6 million mentioned above
resulted in a remaining overall liability of $126 million. Columbia
Transmission's environmental cash expenditures are expected to be approximately
$18 million in 1997 and continue annually at that level for the foreseeable
future. These expenditures will be charged against Columbia Transmission's
previously recorded liability. Management does not believe that Columbia
Transmission's environmental expenditures will have a material adverse effect on
its operations, liquidity or financial position, based on known facts and
existing laws and regulations and the long period over which expenditures will
be made. In addition, as a result of reapplying SFAS No. 71 in 1995, a
regulatory asset has been recorded to the extent environmental expenditures are
expected to be recovered through rates. Columbia Transmission is also currently
involved in pursuing recovery of environmental expenditures from its insurance
carriers. At this time, management is unable to determine the extent, if any, of
recovery.

In addition, predecessor companies of Columbia Transmission may have been
involved in the operation of manufactured gas plants. When such plants were
abandoned, material used and created in the process was sometimes buried at the
site.


                                       23
<PAGE>   24
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
             OF OPERATIONS (Continued)

From its investigations, Columbia Transmission is unable at this time to
determine if it will become liable for any characterization or remediation costs
at such sites.

Secondary Market Transactions

In 1996, FERC initiated a pilot program to assess the impact of lifting price
caps on secondary market transactions and selected Columbia Transmission and one
of its customers as potential participants. While Columbia Transmission was
prepared to proceed with the pilot, the distribution company chose to withdraw.

Cove Point Facility

Columbia LNG is a partner with subsidiaries of the Potomac Electric Power
Company in Cove Point LNG Limited Partnership (Cove Point LNG). In 1995, Cove
Point LNG began commercial operation of one of the largest natural gas peaking
and storage facilities in the United States located near Cove Point, Maryland.
The facility has a capacity to liquefy natural gas at a rate of 15,000 Mcf/d and
stores the resulting liquefied natural gas (LNG) until needed for the winter
peak-day requirements of utilities and other customers. Cove Point LNG also owns
a pipeline system in Maryland and Northern Virginia that provides natural gas
transportation services.

In addition to its peaking and transportation operations, Cove Point LNG
maintains a currently inactive marine terminal capable of unloading LNG tankers.
Cove Point may reactivate the marine terminal at a future date if warranted by
market conditions and customer demand for its LNG and natural gas services.

Volumes

Columbia Transmission's throughput consists of transportation and storage
services for local distribution companies and other customers within its market
area. Throughput is recorded for market-area storage services as gas is
withdrawn from storage. Throughput for Columbia Gulf consists of mainline
transportation services from Louisiana to West Virginia and short-haul
transportation services from the Gulf of Mexico to Rayne, Louisiana.

Total throughput for the transmission and storage segment totaled 1,378.1 Bcf
for 1996, an increase of 41.9 Bcf over 1995 largely due to increased marketing
efforts on Columbia Gulf's system and increased demand resulting from the colder
weather in 1996. Total throughput for 1995 was 1,336.2 Bcf, an increase of 64.2
Bcf from 1994. This improvement reflected increased demand stemming from the
colder weather during the fourth quarter of 1995 and increased summer-related
requirements from electric cogeneration facilities.

Columbia Transmission's market area transportation is 3.7 Bcf lower in 1996
primarily due to additional transportation services utilized in the summer of
1995 and increased storage withdrawals in the last quarter of 1995 to meet
colder weather demands. Partially offsetting the decline was an increase in
transportation services due to the 14% colder weather in the first quarter of
1996. Market area transportation increased 67.5 Bcf in 1995 over 1994 due to the
impact of colder weather in 1995 which resulted in customers increasing
utilization of Columbia Transmission's transportation services.

Mainline transportation increased 28.7 Bcf in 1996 reflecting the impact of
colder weather during the 1995-1996 winter heating season which had the effect
of substantially depleting Columbia Transmission customers' storage inventories.
As a result, Columbia Gulf's mainline transportation services were heavily
utilized during the 1996 summer period to refill depleted gas inventories for
the 1996-1997 winter heating season.

An increase of 45.1 Bcf in short-haul transportation in 1996 reflected increased
production at Vermillion and Eugene Island as well as new sources of supply in
the Eugene Island, South Marsh Island and West Cameron areas. New
interconnections in Louisiana also contributed to the increase in throughput. In
1995, short-haul transportation was essentially unchanged from the prior year as
the impact of customers using facilities other than Columbia Gulf's to transport
gas requirements was offset by colder weather and additional natural gas
supplies available for transportation and increased marketing efforts.

Under Order 636, a significant portion of the transmission and storage segment's
fixed costs are being recovered through a monthly demand charge. As a result,
variations in throughput have little effect on income.


                                       24
<PAGE>   25
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
             OF OPERATIONS (Continued)

Operating Revenues

Operating revenue for 1996 of $810.8 million increased $50.5 million over the
prior period. After adjusting for the recovery of upstream transportation costs
and certain other revenues that are fully offset in operating expense, current
period operating revenues increased $37.7 million. This increase was primarily
due to the new rates in place for Columbia Transmission effective February 1,
1996, subject to refund. Partially offsetting these improvements was the
recognition of $12.2 million in exit fees collected by Columbia Gulf during
1995.

Operating revenues for 1995 were relatively unchanged from 1994 at $760.3
million.

Operating Income

Operating income for 1996 decreased $5.2 million compared to 1995 to a level of
$207.8 million. Operating expenses increased $55.7 million in 1996 due in large
part to an increase of $29 million for restructuring charges, employee incentive
awards and items that had no effect on income. The non-income effecting items
are primarily costs that are allowed to be recovered in current rates as they
are incurred. The impacts of bankruptcy recorded in 1995, including an increase
in franchise taxes as a result of emergence, also contributed to the decline in
operating income. Partially offsetting these decreases was a $2.8 million
improvement in operating income for Columbia LNG, reflecting its first full year
of commercial operations.

Operating income for 1995 increased $3.3 million over 1994 to $213 million, due
in part to lower operating expenses of $1.7 million. Operating expenses were
higher in 1994 due to approximately $19.1 million for Columbia Gulf's
environmental accruals and $8 million in severance and relocation expense.


                                       25
<PAGE>   26
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
             OF OPERATIONS (Continued)

    STATEMENTS OF OPERATING INCOME FROM TRANSMISSION AND STORAGE OPERATIONS
                                  (UNAUDITED)

<TABLE>
<CAPTION>
Year Ended December 31 (in millions)      1996        1995       1994
---------------------------------------------------------------------
<S>                                     <C>         <C>        <C>   
OPERATING REVENUES
    Transportation revenues             $629.0      $612.7     $650.7
    Storage revenues                     159.5       139.3      141.7
    Other revenues                        22.3         8.3      (33.7)
---------------------------------------------------------------------
Total Operating Revenues                 810.8       760.3      758.7
---------------------------------------------------------------------
OPERATING EXPENSES
    Operation and maintenance            444.1       392.5      391.1
    Depreciation                         102.6       103.8      103.9
    Other taxes                           56.3        51.0       54.0
---------------------------------------------------------------------
Total Operating Expenses                 603.0       547.3      549.0
---------------------------------------------------------------------
OPERATING INCOME                        $207.8      $213.0     $209.7
---------------------------------------------------------------------
</TABLE>

                  TRANSMISSION AND STORAGE OPERATING HIGHLIGHTS

<TABLE>
<CAPTION>
                                           1996        1995        1994        1993        1992
-----------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions)      142.7       172.5       179.1       137.2       114.2
-----------------------------------------------------------------------------------------------
<S>                                     <C>         <C>         <C>           <C>         <C>  
THROUGHPUT (Bcf)
Transportation
     Columbia Transmission
        Market area                     1,102.4     1,106.1     1,038.6       895.9       909.0
     Columbia Gulf
        Main-line                         633.7       605.0       590.3       579.9       574.3
        Short-haul                        266.5       221.4       225.4       258.1       258.3
     Intrasegment eliminations           (624.5)     (596.3)     (583.2)     (561.7)     (563.3)
-----------------------------------------------------------------------------------------------
Total Transportation                    1,378.1     1,336.2     1,271.1     1,172.2     1,178.3
Sales                                        --          --         0.9       183.7       196.0
-----------------------------------------------------------------------------------------------
Total Throughput                        1,378.1     1,336.2     1,272.0     1,355.9     1,374.3
-----------------------------------------------------------------------------------------------
</TABLE>


                                       26
<PAGE>   27
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
             OF OPERATIONS (Continued)

                             DISTRIBUTION OPERATIONS

Market Conditions

Weather during 1996 in the market area served by Columbia's distribution
companies (Distribution) was the coldest of the decade and the fifth coldest in
Distribution's history. Weather was 5% colder than 1995 and 6% colder than
normal, resulting in a 16 Bcf improvement over 1995 in Distribution's
weather-sensitive deliveries. While the economy in Distribution's service
territory remained strong, deliveries to industrial customers were down 6.6 Bcf,
or 3% from 1995. This throughput decline reflects reduced deliveries of
approximately 13.5 Bcf to low margin electric power generation customers who
switched to alternate fuels because of higher gas prices. Also, the mild summer
weather reduced air conditioning requirements. A labor strike, shutting down
production of a major customer, caused a 3.4 Bcf decline. Distribution added
about 22,000 net residential and commercial customers during the year, a 1%
growth rate which tracks previous year's growth.

Competition

Distribution competes with investor-owned, municipal, and cooperative electric
utilities throughout its five-state service area. Competition is generally
strongest in the residential and commercial markets of Kentucky, southern Ohio
and southwestern Pennsylvania where electric rates are driven by low-cost
coal-fired generation. Areas such as northern Ohio and Pittsburgh, Pa. have less
competitive electric rates, due to the use of higher-cost nuclear-generated
power. Distribution continues to capture a major portion of the energy market
for newly built homes as a result of a strong customer preference for natural
gas.

Approximately 40 percent of Distribution's industrial and commercial throughput,
or 128 Bcf, is susceptible to bypass, because these customers are geographically
located close to multiple natural gas pipelines and local gas distribution
companies. With the use of innovative rate and capacity release strategies and
the negotiation of unique customer arrangements, substantial inroads by other
natural gas competitors have been avoided to date. As a result of these actions,
the current estimated throughput exposure has been reduced to approximately 43
Bcf, representing about $11 million in annual net revenue.

Regulatory Matters

Columbia Gas of Ohio, Inc.'s (Columbia of Ohio) 1994 rate case settlement
provided for a review of the company's revenue requirements by a group
comprising diverse interested parties, also known as the Collaborative, for the
purpose of evaluating the need to adjust base rates on May 1, 1996. The review
process was completed in late 1996 and resulted in the filing of two significant
pleadings with the Public Utilities Commission of Ohio (PUCO).

On October 17, 1996, Columbia of Ohio filed an application for approval of a
"Customer Choice" transportation program for residential and small commercial
customers. The application was approved by the PUCO in January 1997. The initial
program design includes options of unbundled services, permitting customers to
purchase gas directly from participating marketers. This program also provides
for the full recovery of stranded upstream pipeline supplier costs. The
tentative start date is April 1, 1997. The target location is the Toledo market
area which includes approximately 159,000 residential customers and 11,200 small
commercial customers. If successful, Columbia of Ohio hopes to expand the
"Customer Choice" program statewide over the next few years. The PUCO approved
the initial program for a one-year period. After a year, the PUCO will review
the program before approving a more permanent program.

On October 28, 1996, Columbia of Ohio filed an unopposed settlement with the
PUCO to resolve its revenue requirement. This filing was approved by the PUCO in
December 1996. The filing permits Columbia of Ohio to retain up to $51 million
of revenues over the next three years subject to a sharing mechanism, under
which a portion of any earnings above an industry composite allowed return on
equity would be shared with customers. The revenues retained are primarily from
off-system sales transactions completed or agreed to prior to August 31, 1996.
As allowed under this settlement, revenues of $11.5 million were recorded in
1996 income, with $19.7 million of revenues eligible for retention in both 1997
and 1998. This revenue mechanism is in lieu of a base rate increase and does not
result in any base rate increase for customers. Additionally, the settlement
provides that Columbia of Ohio will not implement any increase in base rates
before January 1, 1999.

In May 1996, legislation was enacted in Ohio that revised state laws governing
natural gas to allow for more competition among suppliers and more choices for
customers. Key provisions of this legislation deregulate the commodity sales of
gas under certain conditions and authorize the PUCO to establish rates by
non-traditional methods, e.g., indexed adjustments, automatic adjustments and
price path. The PUCO is required to adopt final regulations implementing the new
law early in 1997.


                                       27
<PAGE>   28
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
             OF OPERATIONS (Continued)

In August 1996, Columbia Gas of Pennsylvania, Inc. (Columbia of Pennsylvania)
received Pennsylvania Public Utility Commission (PPUC) approval of a residential
transportation rate schedule and a two-year residential transportation pilot
program. Under the pilot program, Columbia of Pennsylvania has assigned a
portion of its upstream pipeline capacity to the transportation customers' third
party suppliers thereby avoiding stranded upstream pipeline costs and the
shifting of such costs to sales customers. This program, which began in November
1996, is one of the largest pilot programs currently underway in the United
States. Columbia of Pennsylvania has more than 36,000 customers in Washington
County and the Borough of Pleasant Hills, with nearly 5,500 electing to
participate in the pilot program. A similar pilot program enlisting 10,000 of
Columbia of Pennsylvania's customers in Allegheny County may take effect in
November 1997.

In May 1996, the PPUC approved Columbia of Pennsylvania's request for a capacity
release incentive program. This program supplements Columbia of Pennsylvania's
existing off-system sales and gas procurement incentive programs.

In Virginia, the Virginia State Corporation Commission (VSCC) approved
Commonwealth Gas Services, Inc.'s (Commonwealth Services) rate case settlement
that was reached in early 1996. In addition to new rates designed to generate
additional gross annual revenues of $6.3 million, the settlement provided for a
separate proceeding to consider gas supply and other incentive proposals. A
hearing on these issues was held in September 1996 and the Hearing Examiner's
recommendation is expected in early 1997.

Commonwealth Services anticipates filing a general rate case in April 1997 to
recover increases in operating costs including an aggressive capital program to
upgrade facilities. Commonwealth Services is experiencing a growth rate three
times higher than its affiliated distribution companies. Also, Commonwealth
Services is evaluating a residential/small commercial transportation pilot
program. The pilot program would be filed with the VSCC to commence during 1997
and continue for a period of two years.

Columbia Gas of Maryland, Inc. (Columbia of Maryland) initiated a new
transportation program for smaller commercial and industrial customers that went
into effect in June 1996 on a pilot basis. Columbia of Maryland also received
approval from the Maryland Public Service Commission (MPSC) for a residential
transportation service pilot program which began in November 1996. Under the
two-year pilot program, Columbia of Maryland has assigned a portion of its
upstream pipeline capacity to the transportation customers' third party
suppliers thereby avoiding stranded upstream pipeline costs and the shifting of
such costs to sales customers. Discussions have begun for the next steps of
Columbia of Maryland's pilot transportation programs which propose changes to
give customers more options in capacity assignment.

In February 1996, the MPSC approved Columbia of Maryland's two-year pilot
programs to implement an off-system sales, a capacity release and a gas
procurement incentive program.

Columbia Gas of Kentucky, Inc. (Columbia of Kentucky) received approval from the
Kentucky Public Service Commission to implement an off-system sales and capacity
release incentive plan on a two-year pilot basis effective August 1, 1996. Also,
Columbia of Kentucky increased annual revenues by $1.5 million, effective
October 1, 1996, through the implementation of the final phase of a three-step
increase as provided in its 1994 general rate case settlement.

Restructuring Activities

As previously reported, Distribution has initiated a restructuring of its
general office and field organizations as part of its ongoing efforts to improve
customer service and streamline operations. The restructuring activities, which
are part of Project Phoenix, allow the five distribution companies to operate as
individual business units and create a Shared Services Center in Columbus, Ohio,
to provide agreed-upon services to these companies. The new organization became
fully operational at the beginning of 1997. In connection with the program,
Distribution recorded $21.4 million of costs representing severance and related
benefit costs related to the elimination of about 400 management, professional
and administrative/technical employees. Commonwealth Services has deferred $1.4
million of these costs pending recovery in future rate proceedings. Any
additional charges or adjustments resulting from this program are not expected
to be significant.

Capital Expenditure Program

In addition to maintaining and upgrading facilities to assure safe, reliable and
efficient operation, Distribution's 1996 capital expenditure program of
approximately $148 million (a decline of $4 million from 1995) included
expenditures of $59 million for extending service to new areas and $71 million
for replacement and betterment projects. The estimated


                                       28
<PAGE>   29
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
             OF OPERATIONS (Continued)

1997 capital expenditure program amounts to approximately $160 million,
including $66 million for new business and development and $77 million for
replacement and betterment projects.

Gas Supply

Distribution's gas supply portfolio, with its large storage component, has the
reliability and flexibility to accommodate the impact of weather variations on
traditional customer demand as well as provide opportunities to increase
revenues through the gas incentive programs discussed earlier. Approximately 50%
of winter season demand comes from storage, 49% from firm interstate
transportation capacity, and one percent from peaking services utilized on the
coldest days. This capacity portfolio allows Distribution to purchase up to 65%
of its annual supply requirements during the lower demand summer season.

Off-system sales are sales or other transactions conducted outside of
Distribution's traditional market. For 1996, Distribution had off-system sales
and exchange volumes of approximately 18.5 Bcf resulting in pre-tax income of
$3.8 million, an increase of 11.2 Bcf and $3.4 million, respectively, from 1995.
This excludes $10.7 million in 1996 from Columbia of Ohio's recent rate
agreement.

As mentioned earlier, weather for calendar year 1996 was 5% colder than 1995 and
6% colder than normal. Throughout 1996, Distribution maintained full service to
firm sales customers without interruption. This colder weather increased the
utilization of Distribution's firm capacity portfolio to serve increased sales
customer demand and therefore reduced the amount of unused capacity available
for release. Proceeds from the release of temporarily unused capacity totaled
$14.2 million during 1996, a decrease of $0.2 million from 1995. Where capacity
release incentive program benchmarks are established, a portion of the proceeds
generated in excess of the benchmark provides income for Distribution. All other
proceeds are recorded as a reduction to gas costs. In 1996, both Columbia of
Pennsylvania and Columbia of Maryland were able to retain a small amount of
capacity release proceeds.

Environmental Matters

Distribution's environmental issues primarily relate to former manufactured gas
plant sites. Distribution previously reported that it had identified 14 former
gas plant sites for which it may have some liability for clean up. Distribution
is currently working with the appropriate regulatory agencies to formulate plans
to further investigate these sites. During 1996, a fifteenth formerly owned
manufactured gas plant site was identified. At this time, it is not possible to
estimate the costs associated with this additional site.

To the extent Distribution's site investigations have been conducted,
remediation plans developed and any responsibility for remediation action
established, the appropriate liabilities have been recorded. Regulatory assets
have also been recorded for a majority of these costs as rate recovery has been
allowed or is anticipated.

Volumes

Distribution's throughput of 565 Bcf in 1996 reflected an 18.4 Bcf increase over
1995 as residential and commercial tariff sales rose 19 Bcf primarily due to
colder weather. Also contributing to the increase in throughput were continued
customer growth and higher off-system sales. Transportation volumes decreased
7.1 Bcf reflecting reduced requirements for power generation, the effect of
increased pressure from competitive fuels due to higher natural gas prices and
the impact of a labor strike which halted production of a major customer.
However, the economy in Distribution's service territories remained strong,
especially in the steel and oil refinery sectors, largely offsetting these
declines.

Distribution's 1995 throughput of 546.6 Bcf reflected an increase of 33.6 Bcf
over 1994 due to higher transportation deliveries, off-system sales, continued
customer growth and colder weather. Transportation deliveries were 23.4 Bcf
higher in 1995 due to strong economic conditions in Distribution's service area.
The 7.2 Bcf increase over 1994 in off-system sales reflected recent changes in
natural gas industry regulations.

Net Revenues

Net revenues for 1996 of $906.7 million were up $85.2 million over 1995. Colder
weather contributed $26 million to the increase in net revenues, higher rates
produced $21.2 million and Columbia of Ohio's retention of certain off-system
sales revenue resulted in another $10.7 million. Transportation revenues were up
$9.3 million, in spite of the throughput decline, as deliveries to higher margin
customers increased. Most of the remaining increase was attributable to customer
growth and higher revenue surcharges that are offset in expense.


                                       29
<PAGE>   30
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
             OF OPERATIONS (Continued)

Net revenues of $821.5 million in 1995 were up $86.7 million due to higher rates
which generated additional revenues of $56.3 million and improved transportation
deliveries that contributed $14.3 million.

Operating Income

Operating income for 1996 of $226 million for Distribution increased $62.4
million over 1995, as the increase in net revenues was only partially offset by
an increase of $22.8 million in operating expenses. Included in the higher
operating expenses were restructuring costs which increased $21.1 million. All
other operation and maintenance expense decreased due to efficiencies and
modernization efforts recently implemented. Plant additions contributed to the
$3.5 million increase in depreciation expense while lower property taxes
resulted in a $0.7 million decline in taxes other than income.

Operating income for 1995 increased $35.3 million over 1994 as higher net
revenues were partially offset by increased operating expenses. Operating
expenses for 1995 were up approximately $51.4 million primarily due to costs
associated with computer applications, labor, and marketing and customer service
activities.


                                       30
<PAGE>   31
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
             OF OPERATIONS (Continued)


     STATEMENTS OF OPERATING INCOME FROM DISTRIBUTION OPERATIONS (UNAUDITED)

<TABLE>
<CAPTION>
Year Ended December 31 (in millions)         1996         1995         1994
---------------------------------------------------------------------------
<S>                                      <C>          <C>          <C>      
NET REVENUES
    Sales revenues                       $2,007.9     $1,677.8     $1,741.9
    Less: Cost of gas sold                1,206.4        952.2      1,088.6
---------------------------------------------------------------------------
    Net Sales Revenues                      801.5        725.6        653.3
---------------------------------------------------------------------------
    Transportation revenues                 119.8        105.3         88.8
    Less: Associated gas costs               14.6          9.4          7.3
---------------------------------------------------------------------------
    Net Transportation Revenues             105.2         95.9         81.5
---------------------------------------------------------------------------
Net Revenues                                906.7        821.5        734.8
---------------------------------------------------------------------------
OPERATING EXPENSES
    Operation and maintenance               463.0        443.0        404.0
    Depreciation                             74.4         70.9         64.5
    Other taxes                             143.3        144.0        138.0
---------------------------------------------------------------------------
Total Operating Expenses                    680.7        657.9        606.5
---------------------------------------------------------------------------
OPERATING INCOME                         $  226.0     $  163.6     $  128.3
---------------------------------------------------------------------------
</TABLE>


                                       31
<PAGE>   32
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
             OF OPERATIONS (Continued)

                        DISTRIBUTION OPERATING HIGHLIGHTS

<TABLE>
<CAPTION>
                                                 1996          1995          1994          1993         1992
--------------------------------------------------------------------------------------------------------------
<S>                                         <C>           <C>           <C>           <C>           <C>      
CAPITAL EXPENDITURES ($ in millions)            148.4         151.8         151.4         117.8          99.7
--------------------------------------------------------------------------------------------------------------
THROUGHPUT (Bcf)
Sales
        Residential                             209.4         196.6         189.7         194.7         186.2
        Commercial                               85.7          79.5          80.8          83.4          81.8
        Industrial and Other                     10.3           7.1           9.7          14.2          15.0
--------------------------------------------------------------------------------------------------------------
Total Sales                                     305.4         283.2         280.2         292.3         283.0
Transportation                                  248.8         255.9         232.5         217.5         203.7
--------------------------------------------------------------------------------------------------------------
Total Throughput                                554.2         539.1         512.7         509.8         486.7
Off-System Sales                                 10.8           7.5           0.3             -             -
--------------------------------------------------------------------------------------------------------------
Total Sold and Transported                      565.0         546.6         513.0         509.8         486.7
--------------------------------------------------------------------------------------------------------------
SOURCES OF GAS FOR THROUGHPUT (Bcf)
Sources of Gas Sold
        Spot market*                            298.7         210.4         235.3         142.3         169.9
        Producers                                47.9          70.9          67.5          56.9          57.1
        Pipelines                                   -            -              -         118.4          84.0
        Storage withdrawals (injections)        (20.8)         23.6         (14.0)         (6.7)        (10.7)
        Company use and other                    (9.6)        (14.2)         (8.3)        (18.6)        (17.3)
--------------------------------------------------------------------------------------------------------------
Total Sources of Gas Sold                       316.2         290.7         280.5         292.3         283.0
Gas received for delivery
        to customers                            248.8         255.9         232.5         217.5         203.7
--------------------------------------------------------------------------------------------------------------
Total Sources                                   565.0         546.6         513.0         509.8         486.7
--------------------------------------------------------------------------------------------------------------
CUSTOMERS
        Residential                         1,815,269     1,794,800     1,764,968     1,737,609     1,711,946
        Commercial                            173,689       172,114       167,067       164,037       161,937
        Industrial and Other                    2,285         2,265         2,312         2,302         2,382
--------------------------------------------------------------------------------------------------------------
        Total                               1,991,243     1,969,179     1,934,347     1,903,948     1,876,265
--------------------------------------------------------------------------------------------------------------
DEGREE DAYS                                     5,975         5,692         5,530         5,677         5,507
--------------------------------------------------------------------------------------------------------------
</TABLE>

*Reflects volumes under purchase contracts of less than one year.


                                       32
<PAGE>   33
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
             OF OPERATIONS (Continued)

                      EXPLORATION AND PRODUCTION OPERATIONS

Market Conditions

Gas prices fluctuated considerably in 1996 but were generally much higher than
in 1995. The high prices experienced in the first half of 1996 weakened in the
third quarter due to mild temperatures, but rebounded sharply in December. As a
result of the sale of Columbia Development, effective December 31, 1995,
Columbia Resources is the remaining subsidiary in the exploration and production
(E&P) segment. Columbia Resources' natural gas prices averaged $2.84 per Mcf in
1996, compared with $2.19 per Mcf in 1995.

Fluctuations in gas prices can cause significant variations in revenues for the
E&P segment. To diminish the impact of these price swings and help stabilize
revenues, the E&P segment uses gas commodity futures and options contracts as
well as swap agreements to hedge the price risk for a portion of its production.
Internal guidelines prohibit speculative trading.

Capital Expenditure Program

Columbia Resources participated in the drilling of 45 gross (27 net) development
wells in 1996, with a success rate of 76%. A portion of the drilling operations
scheduled for 1996 was deferred until 1997 to permit time for management to
implement new strategies for its drilling program. These new strategies will
result in tighter scheduling and more concerted development activities which are
designed to lower average finding and development costs. The deferral of
drilling activity in 1996 also permitted Columbia Resources' management to
establish new processes necessary to allow for more aggressive drilling efforts
in 1997. The capital expenditure program for 1997, which is primarily for
drilling activities, is approximately $39 million compared to $12 million in
1996.

Gathering Facilities

On April 29, 1996, Columbia Transmission filed a request with FERC for
abandonment and transfer of certain gathering facilities to Columbia Resources.
Columbia Resources also requested FERC to disclaim jurisdiction over these
assets. Interventions and protests were subsequently filed by producers and
other interested parties. Columbia Resources has reached an agreement in
principle with the Independent Oil & Gas Association of West Virginia and
various Kentucky producers regarding rates and retainage to be charged for
gathering services on the facilities. This agreement covers a four-year period
commencing with the effective date of the transfer. Columbia Resources also has
reached separate agreements with local distribution companies served by these
facilities. FERC approval for the abandonment and transfer of these assets by
Columbia Transmission to Columbia Resources is expected by mid-1997.

Sale of Columbia Development

On April 30, 1996, (effective December 31, 1995) Columbia sold Columbia
Development to a privately-held concern for approximately $200 million. Columbia
Development had approximately 196 billion cubic feet equivalent of proved
natural gas and oil reserves located in the Gulf of Mexico and on-shore
continental United States. An estimated loss of $54.8 million after-tax was
recorded in the fourth quarter of 1995 to reflect the sale of this subsidiary.
In the second quarter of 1996, an adjustment was recorded that reduced the loss
to $49.2 million.

Reserves

Net proved gas reserves for 1996 totaled approximately 645 Bcf, an increase of
45 Bcf over 1995. This increase reflects additional reserves that are available
to be produced under current market conditions. In 1995, net proved gas reserves
totaled approximately 600 Bcf compared with 684 Bcf the year earlier, due to the
sale of Columbia Development.

Proved reserves for oil, condensate and natural gas liquids decreased from 1.7
million barrels at the end of 1995 to 0.8 million barrels at the end of 1996.

Merger of Columbia Coal Gasification Corporation

In July 1996, Columbia Coal Gasification Corporation was merged into Columbia
Resources in order to increase administrative and operating efficiencies.
Columbia Resources has initiated an auction of the coal assets acquired in this
merger which is projected to result in a sale during 1997.

Volumes

Gas production decreased 49% to 33.6 Bcf in 1996 due to the sale of Columbia
Development. After adjusting for this sale, gas production was essentially
unchanged. From 1994 to 1995, production volumes decreased 1.9% to 65.4 Bcf due
to normal production declines from onshore wells in the Southwest while gas
production in the Appalachian area was essentially unchanged.


                                       33
<PAGE>   34
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
             OF OPERATIONS (Continued)

Oil and liquids production decreased by 2.6 million barrels in 1996 due to the
sale of Columbia Development. After adjusting for this sale, oil and liquids
production was essentially unchanged. In 1995, oil and liquids production
declined 21.1% to 2.8 million barrels from 1994 due to decreases in onshore well
production and gas processing.

Operating Revenues

In 1996, operating revenues were $104.5 million, a decrease of $76.1 million
from 1995, reflecting the sale of Columbia Development. Gas revenues for
Columbia Resources increased $22 million, as a result of higher average prices.
Operating revenues of $180.6 million in 1995 were down $24.7 million from 1994
primarily due to lower gas prices and significantly lower oil and liquids
production in the Southwest.

Operating Income

Operating income in 1996 increased $26.3 million to $30 million primarily
reflecting the improvement in average gas prices over the past year. Operating
expenses in 1996 were $102.4 million lower than 1995 due to the sale of Columbia
Development at year end 1995 as well as reengineering initiatives implemented by
Columbia Resources that resulted in a 40% reduction in its administrative and
professional workforce. From 1994 to 1995, operating income had declined $26.9
million to $3.7 million as the result of lower operating revenues.


                                       34
<PAGE>   35
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
             OF OPERATIONS (Continued)



   STATEMENTS OF OPERATING INCOME FROM EXPLORATION AND PRODUCTION OPERATIONS
                                  (UNAUDITED)


<TABLE>
<CAPTION>
Year Ended December 31 (in millions)      1996       1995      1994
-------------------------------------------------------------------
<S>                                     <C>        <C>       <C>   
OPERATING REVENUES
    Gas                                 $ 99.1     $134.4    $150.7
    Oil and liquids                        5.4       46.2      54.6
-------------------------------------------------------------------
Total Operating Revenues                 104.5      180.6     205.3
-------------------------------------------------------------------
OPERATING EXPENSES
    Operation and maintenance             37.0       79.6      76.9
    Depreciation and depletion            28.8       86.9      86.2
    Other taxes                            8.7       10.4      11.6
-------------------------------------------------------------------
Total Operating Expenses                  74.5      176.9     174.7
-------------------------------------------------------------------
OPERATING INCOME                        $ 30.0     $  3.7    $ 30.6
-------------------------------------------------------------------
</TABLE>


                EXPLORATION AND PRODUCTION OPERATING HIGHLIGHTS*


<TABLE>
<CAPTION>
                                         1996     1995      1994      1993      1992
------------------------------------------------------------------------------------
<S>                                     <C>      <C>      <C>       <C>       <C>  
CAPITAL EXPENDITURES ($ in millions)     12.1     86.8     101.6      95.1      70.8
------------------------------------------------------------------------------------
PROVED RESERVES
Gas (Bcf)                               644.5    599.5     683.8     697.0     779.5
Oil and Liquids (000 barrels)             774    1,651    12,255    12,792    14,650
------------------------------------------------------------------------------------
PRODUCTION
Gas (Bcf)                                33.6     65.4      66.7      71.5      69.2
Oil and Liquids (000 barrels)             281    2,849     3,611     3,603     3,061
------------------------------------------------------------------------------------
AVERAGE PRICES
Gas ($ per Mcf)**                        2.84     1.96      2.18      2.28      2.02
Oil and Liquids ($ per barrel)          19.07    16.17     15.09     16.17     18.20
------------------------------------------------------------------------------------
</TABLE>

 *  Years 1992 through 1995 include operating results from Columbia Development
    that was sold effective December 31, 1995.
 ** Includes the effect of hedging activities.


                                       35
<PAGE>   36
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF OPERATIONS (Continued)

                     MARKETING, PROPANE AND POWER GENERATION

Marketing Initiatives

Columbia Energy Services Corporation (Columbia Energy) is Columbia's
nonregulated natural gas marketing company. It provides gas supply, fuel
management and transportation-related services to a diverse customer base,
including cogenerators, local distribution companies, industrial plants,
commercial businesses, joint marketing partners and residences. In 1996,
Columbia Energy made its residential debut in an unbundling pilot program in
Washington County, Pennsylvania. This first-time effort resulted in
approximately 5,000 residential customers for Columbia Energy.

Columbia Energy formed a wholly-owned subsidiary, Columbia Service Partners,
Inc. (Columbia Service) to provide a variety of nonregulated products and
services to both homeowners and businesses. The new company's initial focus is
on the energy-related needs of Distribution's customers. In the second quarter
of 1996, Columbia Service introduced Appliance Partner, a service which offers
customers prompt appliance repair from qualified independent contractors for a
monthly premium. Another service provided by Columbia Service, similar to
Appliance Partner, is Gas Line Guarantee. This service provides for repairs and
replacement of customer-owned gas service lines running from the street to the
house. Columbia Service has also initiated a billing insurance program, Payment
Partner, for customers within certain areas of Distribution's service territory.
As of year-end 1996, Columbia Service had nearly 26,000 customers among the
three programs. In the future, Columbia Service expects to complement these
services with warranty and energy management services to commercial and
industrial customers. These new programs are part of Columbia's ongoing effort
to become a full service provider of energy and energy-related services.

Columbia Network Services

In late 1996, Columbia formed Columbia Network Services Corporation (Columbia
Network), a wholly-owned subsidiary, to provide telecommunications and
information services. Columbia Network's primary focus is to assist personal
communications service (PCS) and other microwave radio service licensees in
locating and constructing antenna facilities as well as maintaining and managing
PCS sites for the licensees. In October 1996, Columbia Network entered into an
agreement with SABRE Decision Technologies (SDT), a division of The SABRE Group,
Inc. to jointly develop an electronic energy information system. During the
initial phase, a standardized electronic bulletin board (EBB) will be designed
for use by the natural gas industry. The EBB will implement FERC-mandated
business standards for electronic gas transportation transactions and provide a
single centralized interface that customers can utilize to conduct business with
a multitude of gas transportation service providers (TSPs). This type of system
is expected to reduce the overall transaction costs of trading and transporting
gas, support the standardization of gas transactions for the natural gas
industry, and allow TSPs to concentrate on their core businesses. Columbia
Network also plans to offer energy management services relating to the
collection and management of customer energy usage information. In addition,
these services may provide opportunities for real-time interactive
communications with customers with respect to a wide variety of information,
products, and services not exclusively energy-related.

Propane

The propane companies serve approximately 79,650 customers in parts of 10
eastern states and the District of Columbia. To increase profitability, the
propane operations continually seek opportunities to improve competitiveness and
expand services which may include acquisitions. During 1996, propane sales by
Columbia Propane Corporation and Commonwealth Propane, Inc. (Commonwealth
Propane) totaled 75.9 million gallons, an increase of 7 million gallons over
1995.

Cogeneration

Columbia is part owner in three cogeneration projects through its subsidiary,
TriStar Ventures Corporation (TriStar). These facilities produce both
electricity and useful thermal energy and are fueled principally by natural gas.
TriStar holds various interests in these facilities that have a total capacity
of approximately 250 megawatts. A fourth project, the Binghamton Cogeneration
Partnership, terminated operations and the power agreement was sold in early
1997. TriStar's primary focus has been the development, ownership and operation
of natural gas-fueled cogeneration power plants selling electric power to local
electric utilities under long-term contract.

TriStar's strategic objective is to develop and/or acquire efficient, natural
gas-fired merchant generating capacity throughout and close to Columbia's
service territories. This will allow TriStar to maximize the synergism afforded
by the System's fuel supply capabilities of Columbia's subsidiaries. Management
believes ownership of these


                                       36
<PAGE>   37
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF OPERATIONS (Continued)

generating assets will add value by complementing Columbia's growth as an
integrated energy supply company by ensuring Columbia's customers access to
reliable, low cost electric energy.

Commodity Hedging

Columbia Energy and Commonwealth Propane use commodity futures to hedge prices
on commitments for natural gas purchases and sales and propane inventories.
Internal guidelines prohibit speculative trading.

Columbia Energy uses commodity futures contracts and basis swaps to assure
acceptable margins on the purchase and resale of natural gas in future months.
When Columbia Energy makes a sale for future delivery without having natural gas
committed to that sale, it purchases commodity futures to reduce the risk of
increasing prices prior to purchasing the natural gas to fulfill the sales
obligation.

Commonwealth Propane purchases propane and places it in inventory for future
sale. Commonwealth Propane sells commodity futures on a portion of its inventory
at the time of purchase to protect it from decreasing prices.

Net Revenues

Net revenues for 1996 increased $9.6 million over 1995 primarily reflecting the
favorable effect of colder weather on the various energy-related operations. Net
revenues from gas marketing activities increased $9.4 million due largely to
sales volumes that almost doubled. Propane operations also experienced an
increase of 10% in volumes sold in 1996 which led to the $2.8 million increase
in net revenues. Net revenues in 1996 from power generation activities were
essentially unchanged from 1995.

There was no change in net revenues between 1995 and 1994 as a small increase in
gas marketing was offset by lower propane and other revenues.

Operating Income

Operating income in 1996 increased a modest $0.3 million over the prior year.
The impact on net revenues of increased gas marketing sales was partially offset
by higher operating expenses due to the startup of Columbia Service and costs
associated with business expansion. The increase in net revenues resulting from
higher gas marketing and propane sales was also tempered by restructuring
expenses and incentive awards.

The $2.6 million decrease in operating income in 1995 to $12.2 million reflected
higher operating expenses for propane operations. Operating income for gas
marketing services was relatively unchanged from the previous year.


                                       37
<PAGE>   38
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF OPERATIONS (Continued)

             STATEMENTS OF OPERATING INCOME FROM MARKETING, PROPANE
                        AND POWER GENERATION (UNAUDITED)

<TABLE>
<CAPTION>
Year Ended December 31 (in millions)      1996      1995      1994
------------------------------------------------------------------
<S>                                     <C>       <C>       <C>   
NET REVENUES
    Gas marketing revenues              $728.0    $237.9    $232.1
    Less: Products purchased             711.5     230.8     225.3
------------------------------------------------------------------
    Net Gas Marketing Revenues            16.5       7.1       6.8
------------------------------------------------------------------
    Propane revenues                      80.7      65.1      63.2
    Less: Products purchased              48.3      35.5      33.4
------------------------------------------------------------------
    Net Propane Revenues                  32.4      29.6      29.8
------------------------------------------------------------------
    Other revenues                         7.7      10.3      10.4
------------------------------------------------------------------
Net Revenues                              56.6      47.0      47.0
------------------------------------------------------------------
OPERATING EXPENSES
    Operation and maintenance             38.8      29.7      27.3
    Depreciation and depletion             3.1       2.6       2.3
    Other taxes                            2.2       2.5       2.6
------------------------------------------------------------------
Total Operating Expenses                  44.1      34.8      32.2
------------------------------------------------------------------
OPERATING INCOME                        $ 12.5    $ 12.2    $ 14.8
------------------------------------------------------------------
</TABLE>

          MARKETING, PROPANE AND POWER GENERATION OPERATING HIGHLIGHTS

<TABLE>
<CAPTION>
                                          1996      1995      1994      1993      1992
--------------------------------------------------------------------------------------
<S>                                     <C>       <C>       <C>       <C>       <C>   
CAPITAL EXPENDITURES ($ in millions)       6.3       6.6       4.7       9.7       8.7
--------------------------------------------------------------------------------------
PROPANE
Gallons sold (millions)                   75.9      68.9      68.5      58.1      63.3
Customers                               79,650    74,308    68,218    67,895    65,899
--------------------------------------------------------------------------------------
</TABLE>


                                       38
<PAGE>   39
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF OPERATIONS (Continued)

                               BANKRUPTCY MATTERS

On November 28, 1995, Columbia and its wholly-owned subsidiary, Columbia Gas
Transmission Corporation (Columbia Transmission), emerged from Chapter 11
protection of the Federal Bankruptcy Code under the jurisdiction of the United
States Bankruptcy Court for the District of Delaware (Bankruptcy Court). Both
Columbia and Columbia Transmission had operated under Chapter 11 protection
since July 31, 1991. Certain unresolved bankruptcy-related matters are still
within the jurisdiction of the Bankruptcy Court.

Unsettled Producer Claims

Columbia Transmission's approved plan of reorganization (Plan) provided that
producers who rejected settlement offers contained in the Plan may continue to
litigate their claims under the Bankruptcy Court approved claims estimation
procedures discussed below. If and when these claims are ultimately allowed, the
producers will receive the same percentage payout on their allowed claims that
other settling producers have received. Under the terms of the Plan, the actual
distribution percentage for all producer allowed claims over $25,000 will not be
less than 68.875% or greater than 72.5%. The exact distribution percentage will
depend on the level of aggregate allowed producer claims. Until the total amount
of contested producer claims is established, 5% of the maximum 72.5% payout to
be distributed to producer claimants for allowed claims and to Columbia for its
unsecured debt claim will be withheld. Additional distributions, if any, will be
made once the total amount of allowed producer claims has been determined.


Producer Claims Estimation Process

In 1992, the Bankruptcy Court approved both the appointment of a claims
mediator, and the implementation of a claims estimation procedure for the
quantification of claims arising from Columbia Transmission's rejection of
above-market gas purchase contracts and other claims by producers related to gas
purchase contracts. In late 1994 and early 1995, the claims mediator issued
Initial and Supplemental Reports on Generic Issues for Natural Gas Contract
Claims and directed producer claimants to submit recalculated claims
incorporating the recommendations and instructions. The recommendations and
instructions set out in the reports have not been considered by the Bankruptcy
Court. In mid-1995 most producers, with which Columbia Transmission had not yet
negotiated settlements, submitted recalculated claims to the claims mediator
amounting to over $2 billion in aggregate. Since mid-1995, additional producers
have settled their claims or resolved them by means of litigation within the
claims estimation process and virtually all of these claims have been allowed by
the Bankruptcy Court at their litigated or settled level. As of the end of
February 1997, approximately $156 million in recalculated claims remain to be
settled.

The claims estimation procedures remain in place for use in the
post-confirmation liquidation of unresolved producer claims. The claims mediator
is holding evidentiary hearings with respect to individual producer claims,
including claim-specific issues not addressed by the reports. Recommendations
made by the claims mediator are subject to review by the Bankruptcy Court, and
all parties have rights of appellate review. When claims are allowed by the
Bankruptcy Court and the allowances become final, Columbia Transmission will
make distributions with respect to those claims pursuant to the Plan. The timing
of this on-going litigation process is impossible to predict. Any distributions
on producer claims ultimately liquidated in an aggregate amount in excess of
those proposed by the Plan will be funded, to the extent necessary, by the 5%
holdback from resolved producers and a matching contribution by the reorganized
Columbia Transmission. If the holdback and matching contributions are exhausted,
any further distribution would be funded entirely by Columbia Transmission.
Columbia has guaranteed the payments to producers in cash or in Columbia common
stock if the holdback amounts are exhausted. Based on the information received
and evaluated to date, Columbia Transmission believes adequate reserves have
been established for resolution of the remaining producer claims and the payment
of any amounts which may ultimately become due to producers with respect to the
5% holdback.


                                       39
<PAGE>   40


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA




<TABLE>
<CAPTION>
-----------------------------------------------------------
Index                                                  Page
-----------------------------------------------------------
<S>                                                    <C>
Report of Independent Public Accountants..............   41
Statements of Consolidated Income.....................   42
Consolidated Balance Sheets...........................   43
Statements of Consolidated Cash Flows.................   45
Statements of Consolidated Common Stock Equity........   46
Notes to Consolidated Financial Statements............   47

Schedule II - Valuation and Qualifying Accounts.......   74
-----------------------------------------------------------
</TABLE>


                                       40
<PAGE>   41
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS


To the Shareholders of The Columbia Gas System, Inc.:


We have audited the accompanying consolidated balance sheets of The Columbia Gas
System, Inc. (a Delaware corporation, the "Corporation") and subsidiaries as of
December 31, 1996 and 1995, and the related statements of consolidated income,
cash flows and common stock equity for each of the three years in the period
ended December 31, 1996. These financial statements are the responsibility of
the Corporation's management. Our responsibility is to express an opinion on
these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of the Corporation and
subsidiaries as of December 31, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting principles.

As discussed in Note 6B, effective January 1, 1994, the Corporation changed its
method of accounting for postemployment benefits pursuant to standards
promulgated by the Financial Accounting Standards Board.

Our audits were made for the purpose of forming an opinion on the basic
consolidated financial statements taken as a whole. The schedule listed in the
Index to Item 8, Financial Statements and Supplementary Data, is presented for
purposes of complying with the Securities and Exchange Commission's rules and is
not part of the basic consolidated financial statements. This schedule has been
subjected to the auditing procedures applied in the audits of the basic
consolidated financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic consolidated financial statements taken as a whole.


ARTHUR ANDERSEN LLP


New York, New York
January 27, 1997


                                       41
<PAGE>   42
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)


                        STATEMENTS OF CONSOLIDATED INCOME
                 The Columbia Gas System, Inc. and Subsidiaries


<TABLE>
<CAPTION>
Year Ended December 31 (in millions except per share amounts)          1996           1995*           1994*
----------------------------------------------------------------------------------------------------------
<S>                                                              <C>            <C>             <C>       
 OPERATING REVENUES
   Gas sales                                                     $  2,679.4     $  1,929.0      $  2,031.3
   Transportation                                                     491.3          487.7           505.7
   Other                                                              183.3          218.5           210.1
----------------------------------------------------------------------------------------------------------
 Total Operating Revenues                                           3,354.0        2,635.2         2,747.1
 OPERATING EXPENSES
   Products purchased                                               1,481.1          820.6           984.2
   Operation                                                          854.5          826.7           774.4
   Maintenance                                                        111.4          116.6           133.7
   Depreciation and depletion                                         215.2          270.0           261.7
   Other taxes                                                        213.6          211.1           209.0
----------------------------------------------------------------------------------------------------------
 Total Operating Expenses                                           2,875.8        2,245.0         2,363.0
 Operating Income                                                     478.2          390.2           384.1
----------------------------------------------------------------------------------------------------------
 OTHER INCOME (DEDUCTIONS)
   Interest income and other, net (Note 15)                            26.1          (58.2)           35.2
   Interest expense and related charges** (Note 16 )                 (166.8)        (988.4)          (14.8)
   Reorganization items, net (Note 2C)                                   --           13.4           (12.3)
----------------------------------------------------------------------------------------------------------
 Total Other Income (Deductions)                                     (140.7)      (1,033.2)            8.1
----------------------------------------------------------------------------------------------------------
 INCOME (LOSS) BEFORE INCOME TAXES, EXTRAORDINARY
    ITEM AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE
                                                                      337.5         (643.0)          392.2
 Income taxes (Note 7)                                                115.9         (210.7)          146.0
----------------------------------------------------------------------------------------------------------
 INCOME (LOSS) BEFORE EXTRAORDINARY ITEM AND
    CUMULATIVE EFFECT  OF ACCOUNTING CHANGE                           221.6         (432.3)          246.2

      Extraordinary item (Note 6A)                                       --           71.6              --
      Cumulative effect of change in accounting for
         postemployment benefits (Note 6B)                               --             --            (5.6)
----------------------------------------------------------------------------------------------------------
 NET INCOME (LOSS)                                               $    221.6     $   (360.7)     $    240.6
----------------------------------------------------------------------------------------------------------

 EARNINGS (LOSS) PER SHARE OF COMMON STOCK
    (based on average shares outstanding)
       Before extraordinary item and accounting change           $     4.12     $    (8.57)     $     4.87
       Extraordinary item                                                --           1.42              --
       Change in accounting for postemployment benefits                  --             --           (0.11)
----------------------------------------------------------------------------------------------------------
Earnings (Loss) Per Share of Common Stock                        $     4.12     $    (7.15)     $     4.76

----------------------------------------------------------------------------------------------------------
DIVIDENDS PAID PER SHARE OF COMMON STOCK                         $     0.60     $       --      $       --
----------------------------------------------------------------------------------------------------------
AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS)                        53,782         50,468          50,560
----------------------------------------------------------------------------------------------------------
</TABLE>

 *   Reference is made to Note 2 of  Notes to Consolidated Financial Statements.

**   Due to the bankruptcy filings, interest expense of approximately $230
     million was not recorded in 1994 (see Note 2 of Notes to Consolidated
     Financial Statements). Interest expense of $982.9 million including
     write-off of unamortized discounts on debentures, was recorded in the
     fourth quarter of 1995.

The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.


                                       42
<PAGE>   43
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)


                           CONSOLIDATED BALANCE SHEETS
                 The Columbia Gas System, Inc. and Subsidiaries




<TABLE>
<CAPTION>

Assets as of December 31 (in millions)                                  1996         1995*
-----------------------------------------------------------------------------------------
<S>                                                                 <C>          <C>     
PROPERTY, PLANT AND EQUIPMENT
   Gas utility and other plant, at original cost                    $6,994.4     $6,903.2
   Accumulated depreciation and depletion                           (3,344.5)    (3,322.0)
-----------------------------------------------------------------------------------------
   Net Gas Utility and Other Plant                                   3,649.9      3,581.2
-----------------------------------------------------------------------------------------
   Gas and oil producing properties, full cost method                  502.8        516.3
   Accumulated depletion                                              (146.4)      (141.1)
-----------------------------------------------------------------------------------------
   Net Gas and Oil Producing Properties                                356.4        375.2
-----------------------------------------------------------------------------------------
Net Property, Plant and Equipment                                    4,006.3      3,956.4
-----------------------------------------------------------------------------------------
  INVESTMENTS AND OTHER ASSETS
     Accounts receivable - noncurrent                                    6.3         91.2
     Unconsolidated affiliates                                          69.0         78.2
     Assets held for sale                                               12.1        182.8
     Other                                                              15.9          2.4
-----------------------------------------------------------------------------------------
Total Investments and Other Assets                                     103.3        354.6
-----------------------------------------------------------------------------------------
  CURRENT ASSETS
      Cash and temporary cash investments                               49.8          8.0
      Accounts receivable
        Customers (less allowance for doubtful accounts of $16.2
             and $12.3, respectively)                                  562.2        429.2
      Other                                                             35.4         81.8
    Income tax refund                                                     --        271.5
    Gas inventory                                                      237.8        172.3
    Other inventories - at average cost                                 45.1         41.5
    Prepayments                                                         73.8         56.9
    Regulatory assets                                                   63.4         76.5
    Underrecovered gas costs                                           104.7          0.2
    Prepaid property tax                                                81.1         77.1
    Exchange gas receivable                                            114.6         20.6
    Other                                                               68.0         40.3
-----------------------------------------------------------------------------------------
Total Current Assets                                                 1,435.9      1,275.9
-----------------------------------------------------------------------------------------
REGULATORY ASSETS                                                      410.1        422.0
DEFERRED CHARGES                                                        49.0         48.1
-----------------------------------------------------------------------------------------
TOTAL ASSETS                                                        $6,004.6     $6,057.0
-----------------------------------------------------------------------------------------
</TABLE>

*Reference is made to Note 2 of Notes to Consolidated Financial Statements.

The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.


                                       43
<PAGE>   44
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)



<TABLE>
<CAPTION>
Capitalization and Liabilities as of December 31 (in millions)        1996         1995*
---------------------------------------------------------------------------------------
<S>                                                               <C>          <C>     
COMMON STOCK EQUITY
 Common stock, par value $10 per share - issued 55,263,659
   and 50,620,180 shares, respectively                            $  552.6     $  506.2
 Additional paid in capital                                          743.2        595.8
 Retained earnings                                                   259.3         69.8
 Unearned employee compensation                                       (1.5)          --
 Cost of treasury stock (1,416,155 shares)                              --        (57.8)
---------------------------------------------------------------------------------------
Total Common Stock Equity                                          1,553.6      1,114.0
PREFERRED STOCK (Note 10)                                               --        399.9
LONG-TERM DEBT (Note 11)                                           2,003.8      2,004.5
---------------------------------------------------------------------------------------
Total Capitalization                                               3,557.4      3,518.4
---------------------------------------------------------------------------------------
CURRENT LIABILITIES
 Short-term debt (Note 12)                                           250.0        338.9
 Accounts and drafts payable                                         348.6        215.7
 Accrued taxes                                                       142.6        271.3
 Accrued interest                                                     14.8         94.3
 Estimated rate refunds                                              114.0         96.1
 Estimated supplier obligations                                      115.1        178.3
 Overrecovered gas costs                                                --         41.7
 Transportation and exchange gas payable                              95.4         46.7
 Other                                                               371.1        295.6
---------------------------------------------------------------------------------------
Total Current Liabilities                                          1,451.6      1,578.6
---------------------------------------------------------------------------------------
OTHER LIABILITIES AND DEFERRED CREDITS
 Deferred income taxes - noncurrent                                  557.7        468.6
 Investment tax credits                                               37.1         38.6
 Postretirement benefits other than pensions                         172.3        208.2
 Regulatory liabilities                                               44.5         44.9
 Other                                                               184.0        199.7
---------------------------------------------------------------------------------------
Total Other Liabilities and Deferred Credits                         995.6        960.0
---------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Notes 2, 3 and 14)                       --           --
---------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES                              $6,004.6     $6,057.0
---------------------------------------------------------------------------------------
</TABLE>


                                       44
<PAGE>   45
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

                      STATEMENTS OF CONSOLIDATED CASH FLOWS
                 The Columbia Gas System, Inc. and Subsidiaries

<TABLE>
<CAPTION>
Year Ended December 31 (in millions)                                         1996        1995*         1994*
-----------------------------------------------------------------------------------------------------------
<S>                                                                      <C>         <C>           <C>     
OPERATING ACTIVITIES
      Net income (loss)                                                  $  221.6    $ (360.7)     $  240.6
      Adjustments for items not requiring (providing) cash:
            Depreciation and depletion                                      215.2       270.0         261.7
            Deferred income taxes                                            78.1        66.1          72.2
            Reapplication of SFAS 71                                           --       (71.6)           --
            Loss on sale of Columbia Gas Development Corp.                     --        77.8            --
            Interest expense settled at emergence                              --       702.9            --
      Payment of Chapter 11 liabilities                                        --    (1,169.1)           --
      Other - net**                                                         (10.8)      (94.0)        (19.4)
      Changes in components of working capital:
            Accounts receivable                                             (64.3)       99.7         135.9
            Income tax refunds                                              271.5          --            --
            Gas inventory                                                   (65.6)       58.0         (32.5)
            Prepayments                                                     (16.3)       12.3          (8.0)
            Accounts payable                                                160.8        38.3         (35.5)
            Accrued taxes                                                   (85.5)     (314.9)         45.7
            Accrued interest                                                (71.5)      (56.5)           --
            Estimated rate refunds                                           17.8       (56.6)       (133.3)
            Estimated supplier obligations                                  (63.2)      (44.0)        (49.7)
            Under/Overrecovered gas costs                                  (146.3)      (18.0)        106.7
            Exchange gas payable                                             46.9        10.4         (31.7)
            Other working capital                                           (25.7)       42.5          20.1
-----------------------------------------------------------------------------------------------------------
Net Cash From Operations                                                    462.7      (807.4)        572.8
-----------------------------------------------------------------------------------------------------------
Investment Activities
      Capital expenditures                                                 (316.4)     (411.0)       (433.6)
      Proceeds received on the sale of Columbia Gas Development Corp.       187.8          --            --
      Sale of partnership interest                                            2.7        10.9            --
      Other investments - net                                                14.3        25.2          (1.3)
-----------------------------------------------------------------------------------------------------------
Net Investment Activities                                                  (111.6)     (374.9)       (434.9)
-----------------------------------------------------------------------------------------------------------
Financing Activities
      Retirement of prepetition debt obligations                               --      (637.3)           --
      Retirement of preferred stock                                        (400.0)         --            --
      Dividends paid                                                        (32.2)         --            --
      Issuance of common stock                                              250.8         1.8            --
      Net increase (decrease) in short-term debt                            (88.9)      338.9            --
      Other financing activities                                            (39.0)        5.1           3.5
-----------------------------------------------------------------------------------------------------------
Net Financing Activities                                                   (309.3)     (291.5)          3.5
-----------------------------------------------------------------------------------------------------------
Increase (Decrease) in cash and temporary cash investments                   41.8    (1,473.8)        141.4
Cash and temporary cash investments at beginning of year                      8.0     1,481.8       1,340.4
-----------------------------------------------------------------------------------------------------------
Cash and temporary cash investments at end of year                       $   49.8    $    8.0      $1,481.8
-----------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
      Cash paid for interest                                                 80.8       284.9           0.8
      Cash paid for income taxes (net of refunds)                           (93.4)       42.3          37.4
-----------------------------------------------------------------------------------------------------------
</TABLE>

   * Reference is made to Note 2 of Notes to Consolidated Financial Statements.
  ** Includes changes in Liabilities Subject to Chapter 11 Proceedings of
     ($2,842.0) million in 1995 and $61.1 million in 1994. The accompanying
     Notes to Consolidated Financial Statements are an integral part of these
     statements.


                                       45
<PAGE>   46
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

                 STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY
                 The Columbia Gas System, Inc. and Subsidiaries




<TABLE>
<CAPTION>
                                                Common Stock*
                             ------------------------------------------    Additional                     Unearned
   (in millions except                 Shares          Par     Treasury       Paid In     Retained        Employee
    for share amounts)       Outstanding(000)        Value        Stock       Capital     Earnings    Compensation       Total
-------------------------------------------------------------------------------------------------------------------------------
<S>                          <C>                  <C>          <C>         <C>            <C>         <C>              <C>
Balance at December 31, 1993           50,559     $  505.6     $     --      $  601.8     $  189.9        $  (70.0)    $1,227.3
Net Income                                                                                   240.6                        240.6
Common stock issued:
  Long-Term Incentive Plan                  4                                     0.1                                       0.1
-------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1994           50,563        505.6           --         601.9        430.5           (70.0)     1,468.0
Net Loss                                                                                    (360.7)                      (360.7)
Termination of LESOP                   (1,416)                    (57.8)         (7.9)                        70.0          4.3
Common stock issued:
  Long-Term Incentive Plan                 57          0.6                        1.8                                       2.4
-------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1995           49,204        506.2        (57.8)        595.8         69.8              --      1,114.0
Net Income                                                                                   221.6                        221.6
Cash Dividends:
  Common Stock                                                                               (32.1)                       (32.1)
Common stock issued:
  Public Offering                       5,750         43.3         57.8         137.5                                     238.6
  Long-Term Incentive Plan                310          3.1                        9.9                         (1.5)        11.5
-------------------------------------------------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1996           55,264     $  552.6     $     --      $  743.2     $  259.3        $   (1.5)    $1,553.6
-------------------------------------------------------------------------------------------------------------------------------
</TABLE>

*100 million shares authorized at December 31, 1996, 1995, 1994 and 1993 - $10
par value. The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.


                                       46
<PAGE>   47
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

                   Notes To Consolidated Financial Statements

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.    PRINCIPLES OF CONSOLIDATION. The consolidated financial statements include
      the accounts of The Columbia Gas System, Inc. (Columbia) and all
      subsidiaries. All intercompany accounts and transactions have been
      eliminated. Certain reclassifications have been made to the 1995 and 1994
      financial statements to conform to the 1996 presentation.

B.    CASH AND CASH EQUIVALENTS. Columbia considers all highly liquid short-term
      debt instruments to be cash equivalents.

      To settle its Chapter 11 prepetition obligations in 1995, Columbia
      distributed approximately $3.6 billion to its creditors. This settlement
      distribution included $2.3 billion for Columbia's prepetition debt and
      approximately $1 billion for interest on that debt. It was funded by $2
      billion in new long-term debt securities, $1 billion in cash, which
      included cash on hand, $0.4 billion of new bank debt, and $0.2 billion in
      Redeemable Preferred Stock, Series A (Series A - Preferred Stock) and $0.2
      billion in Convertible Preferred Stock, Series B (Series B-DECS). The
      issuance of these securities represented non-cash financing activities. In
      February 1996, Columbia redeemed the Series A-Preferred Stock and Series
      B-DECS as allowed under the terms of Columbia's approved plan of
      reorganization.

C.    BASIS OF ACCOUNTING FOR RATE-REGULATED SUBSIDIARIES. Statement of
      Financial Accounting Standards No. 71, "Accounting for the Effects of
      Certain Types of Regulation" (SFAS No. 71), provides that rate-regulated
      public utilities account for and report assets and liabilities consistent
      with the economic effect of the way in which regulators establish rates,
      if the rates established are designed to recover the costs of providing
      the regulated service and if the competitive environment makes it
      reasonable to assume that such rates can be charged and collected. As more
      fully discussed in Note 6A, Columbia's transmission subsidiaries reapplied
      the provisions of SFAS No. 71 during 1995, concurrent with the emergence
      from Chapter 11 protection. Columbia's gas distribution subsidiaries have
      been following and continue to follow the accounting and reporting
      requirements of SFAS No. 71.

      Certain expenses and credits subject to utility regulation or rate
      determination normally reflected in income are deferred on the balance
      sheet and are recognized in income as the related amounts are included in
      service rates and recovered from or refunded to customers. Condensed
      information for assets and liabilities subject to utility regulation and
      rate determination are as follows:

<TABLE>
<CAPTION>
                                                                      Transmission                    Distribution
                                                                      Subsidiaries                    Subsidiaries
At December 31 ($ in millions)                                    1996            1995            1996            1995
----------------------------------------------------------------------------------------------------------------------
<S>                                                              <C>             <C>             <C>             <C>
ASSETS
     Environmental costs                                         123.6           132.5             7.1             8.2
     Postemployment and postretirement benefits                   69.4            76.4           129.9           138.0
     Percent of income plan receivables                             --              --            17.9            16.5
     Retirement income plan costs                                 21.4            14.6            20.2            17.8
     Regulatory effects of accounting for income taxes              --              --            49.0            50.9
     Post in-service carrying charges                               --              --            18.9            24.4
     Underrecovered gas costs                                       --              --           104.7              --
     Other                                                         9.9             9.3             6.3             9.9
----------------------------------------------------------------------------------------------------------------------
Total regulatory assets                                          224.3           232.8           354.0           265.7
----------------------------------------------------------------------------------------------------------------------
LIABILITIES
    Rate refunds and reserves                                     95.5            36.0            18.4            60.1
    Overrecovered gas costs                                         --              --              --            41.7
    Regulatory effects of accounting for income taxes             21.5            23.4            25.2            25.5
    Other                                                          6.8             5.2              --              --
----------------------------------------------------------------------------------------------------------------------
Total regulatory liabilities                                     123.8            64.6            43.6           127.3
----------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       47
<PAGE>   48
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

D.    GAS UTILITY AND OTHER PLANT AND RELATED DEPRECIATION. Property, plant and
      equipment (principally utility plant) are stated at original cost. The
      cost of gas utility and other plant of the rate regulated subsidiaries
      includes an allowance for funds used during construction (AFUDC).
      Property, plant and equipment of other subsidiaries includes interest
      during construction (IDC). The 1996 before-tax rates for AFUDC and IDC
      were 6.15 percent and 6.9 percent, respectively. The 1995 and 1994
      before-tax rates for AFUDC and IDC were 8 percent and 9.6 percent,
      respectively.

      Improvements and replacements of retirement units are capitalized at cost.
      When units of property are retired, the accumulated provision for
      depreciation is charged with the cost of the units and the cost of
      removal, net of salvage. Maintenance, repairs and minor replacements of
      property are charged to expense. Columbia's subsidiaries provide for
      annual depreciation on a composite straight-line basis.

      The average annual depreciation rate for the transmission subsidiaries'
      property was 2.5 percent in 1996, 2.6 percent in 1995 and 2.7 percent in
      1994. The average annual depreciation rate for the distribution
      subsidiaries' property was 3.4 percent in 1996 and 3.3 percent in 1995 and
      1994.

E.    GAS AND OIL PRODUCING PROPERTIES. Columbia's subsidiaries engaged in
      exploring for and developing gas and oil reserves follow the full cost
      method of accounting. Under this method of accounting, all productive and
      nonproductive costs directly identified with acquisition, exploration and
      development activities including certain payroll and other internal costs
      are capitalized. Depletion for those subsidiaries is based upon the ratio
      of current-year revenues to expected total revenues, utilizing current
      prices, over the life of production. If costs exceed the sum of the
      estimated present value of the net future gas and oil revenues and the
      lower of cost or estimated value of unproved properties, an amount
      equivalent to the excess is charged to current depletion expense. Gains or
      losses on the sale or other disposition of gas and oil properties are
      normally recorded as adjustments to capitalized costs, except in the case
      of a sale of a significant amount of properties, which could be reflected
      in the income statement.

      On April 30, 1996, Columbia sold Columbia Gas Development Corporation
      (Columbia Development) effective December 31, 1995, to a privately held
      exploration and development firm for approximately $200 million. The sale
      included approximately 196 billion cubic feet equivalent of proved gas and
      oil reserves, located in the Gulf of Mexico and on-shore continental
      United States. An after-tax loss of $54.8 million was recorded in the
      fourth quarter of 1995. An adjustment to the loss of $5.6 million
      after-tax was recorded during 1996.

F.    COMMODITY HEDGING. Premiums paid for option and swap agreements are
      included as current assets in the consolidated balance sheet until they
      are exercised or expire. Margin requirements for natural gas, crude oil
      and propane futures are also recorded as current assets. Unrealized gains
      and losses on all futures contracts are deferred on the consolidated
      balance sheet as either current assets or other deferred credits. Realized
      gains and losses from the settlement of natural gas and crude oil futures,
      options and swaps are included in revenues or products purchased as
      appropriate. Realized gains and losses from the settlement of propane
      futures contracts are included in products purchased.

G.    GAS INVENTORY. The distribution subsidiaries' gas inventory is carried at
      cost on a last-in, first-out (LIFO) basis. The excess of replacement cost
      of gas inventory at December 31, 1996, over the carrying value is
      approximately $157 million. Liquidation of LIFO layers related to gas
      delivered by the distribution subsidiaries does not affect income since
      the effect is passed through to customers as part of purchased gas
      adjustment tariffs.

H.    INCOME TAXES AND INVESTMENT TAX CREDITS. Columbia and its subsidiaries
      record income taxes to recognize full interperiod tax allocations. Under
      the liability method of income tax accounting, deferred income taxes are
      recognized for the tax consequences of temporary differences by applying
      enacted statutory tax rates applicable to future years to differences
      between the financial statement carrying amounts and the tax basis of
      existing assets and liabilities.

      Previously recorded investment tax credits of the regulated subsidiaries
      were deferred and are being amortized over the life of the related
      properties to conform with regulatory policy.

I.    ESTIMATED RATE REFUNDS. Certain rate-regulated subsidiaries collect
      revenues subject to refund pending final determination in rate
      proceedings. In connection with such revenues, estimated rate refund
      liabilities are


                                       48
<PAGE>   49
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

      recorded which reflect management's current judgment of the ultimate
      outcome of the proceedings. No provisions are made when, in the opinion of
      management, the facts and circumstances preclude a reasonable estimate of
      the outcome.

J.    DEFERRED GAS PURCHASE COSTS. Columbia's gas distribution subsidiaries
      defer differences between gas purchase costs and the recovery of such
      costs in revenues, and adjust future billings for such deferrals on a
      basis consistent with applicable tariff provisions.

K.    REVENUE RECOGNITION. Columbia's gas distribution subsidiaries bill
      customers on a monthly cycle billing basis. Revenues are recorded on the
      accrual basis including an estimate for gas delivered but unbilled at the
      end of each accounting period.

L.    ENVIRONMENTAL EXPENDITURES. Columbia accrues for costs associated with
      environmental remediation obligations when such costs are probable and can
      be reasonably estimated, regardless of when expenditures are made. The
      undiscounted estimated future expenditures are based on currently enacted
      laws and regulations, existing technology and, when possible,
      site-specific costs. The reserve is adjusted as further information is
      developed or circumstances change. Rate-regulated subsidiaries applying
      SFAS No. 71 establish a regulatory asset on the balance sheet to the
      extent that future recovery of environmental remediation costs is expected
      through the regulatory process.

M.    USE OF ESTIMATES. The preparation of financial statements in conformity
      with generally accepted accounting principles requires management to make
      estimates and assumptions that affect reported amounts of assets and
      liabilities and disclosure of contingent assets and liabilities at the
      date of the financial statements and the reported amounts of revenues and
      expenses during the reporting period. Actual results could differ from
      those estimates.

N.    STOCK OPTIONS AND AWARDS. Statement of Financial Accounting Standards No.
      123, "Accounting for Stock-Based Compensation," (SFAS No. 123), effective
      in 1996, encourages, but does not require, entities to adopt the fair
      value method of accounting for stock based compensation plans. This
      statement requires the value of the option at the date of grant be
      amortized over the vesting period of the option. Columbia continues to
      apply Accounting Principles Board Opinion No. 25, "Accounting for Stock
      Issued to Employees" (APB Opinion No. 25).

      For stock appreciation rights, compensation expense is recognized on the
      aggregate difference between the market price of Columbia's stock and the
      option price. Compensation expense related to contingent stock awards is
      recognized over the vesting period. Columbia sets the grant price of the
      options at the market price of the stock on the grant date. In accordance
      with APB Opinion No. 25, expense related to stock options is measured by
      the difference between the grant price and Columbia's stock price on the
      measurement date (grant date). Since the difference between the grant
      price and Columbia's stock price on the measurement date is de minimus, no
      compensation expense is recognized. When stock options are exercised,
      common stock is credited for the par value of shares issued and additional
      paid in capital is credited with the consideration in excess of par.

2.    EMERGENCE FROM CHAPTER 11 OF THE BANKRUPTCY CODE

A.    GENERAL. On November 28, 1995, both Columbia and Columbia Transmission
      emerged from Bankruptcy Court protection under Chapter 11 of the Federal
      Bankruptcy Code. While under Chapter 11 protection, actions by creditors
      to collect prepetition indebtedness were stayed and other contractual
      obligations could not be enforced against either Columbia or Columbia
      Transmission. Both Columbia and Columbia Transmission had the right,
      subject to Bankruptcy Court approval and certain other limitations, to
      assume or reject executory contracts and unexpired leases. Any claims for
      damages resulting from rejection were treated as general unsecured claims
      in the reorganization. The parties affected by these rejections had the
      right to file claims with the Bankruptcy Court in accordance with
      bankruptcy procedures. Prepetition claims which were contingent or
      unliquidated at the commencement of the Chapter 11 proceeding were
      generally allowable against the debtor companies in amounts fixed by the
      Bankruptcy Court. Substantially all liabilities as of the petition date
      were subject to resolution under plans of reorganization approved by the
      Bankruptcy Court. Columbia's reorganization plan was also approved by the
      Securities and Exchange Commission (SEC) under the Public Utility Holding
      Company Act of 1935.


                                       49
<PAGE>   50
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

      In settlement of its prepetition obligations, Columbia distributed
      approximately $3.6 billion to its creditors, which included $2.3 billion
      in payment of Columbia's prepetition debt and approximately $1 billion of
      interest on that debt. Columbia's approved plan of reorganization (Plan)
      provided for payment to its creditors of the full amount of their
      principal balances and accrued prepetition and postpetition interest and
      interest on overdue interest through distribution of:

            -     $2 billion in new debt securities, with maturities ranging
                  from 5 to 30 years;

            -     $1 billion in cash, funded by cash on hand and new bank debt;
                  and

            -     $200 million in Redeemable Preferred Stock, Series A and $200
                  million in Convertible Preferred Stock, Series B (subsequently
                  redeemed in February 1996).

      The interest rates on the new debt securities and the dividend rates and
      other financial terms of the new equity securities were based on market
      levels at the time of emergence. Columbia's new long-term debt obligations
      were rated as investment grade by three major rating agencies.

      Columbia Transmission's Plan is guaranteed financially by Columbia, and
      provided a total distribution of approximately $3.9 billion to its
      creditors of which approximately $1.2 billion represented producer claims.
      Columbia Transmission's Plan provided that producers who rejected
      settlement offers contained in Columbia Transmission's Plan may continue
      to litigate their claims under the Bankruptcy Court-approved claims
      estimation procedures, described below, and receive the same percentage
      payout on their allowed claims, when and if ultimately allowed, as
      received by the settling producers. Columbia Transmission's Plan further
      provided that the actual distribution percentage for all producer claims,
      which would not be less than 68.875% or greater than 72.5%, could not be
      determined until the total amount of contested producer claims is
      established, and until such time, 5% of the maximum amount (based on a
      72.5% payout) to be distributed to producer claimants for allowed claims
      and to Columbia for unsecured debt will be withheld. Additional
      distributions, if any, will be made when the total amount of allowed
      producer claims has been determined.

B.    PRODUCER CLAIMS ESTIMATION PROCESS. In 1992, the Bankruptcy Court approved
      the appointment of a claims mediator and the implementation of a claims
      estimation procedure for the quantification of claims arising from the
      rejection of above-market gas purchase contracts and other claims by
      producers related to gas purchase contracts with Columbia Transmission. In
      late 1994 and early 1995, the claims mediator issued Initial and
      Supplemental Reports On Generic Issues for Natural Gas Contract Claims and
      directed producer claimants to submit recalculated claims. The
      recommendations and instructions set out in the reports have not been
      considered by the Bankruptcy Court. In mid-1995, most producers with which
      Columbia Transmission had not yet negotiated settlements submitted
      recalculated claims to the claims mediator. Those recalculated claims
      amounted to over $2 billion. Since mid-1995, numerous additional producers
      have settled their claims or resolved them by means of litigation within
      the claims estimation process and virtually all of these claims have been
      allowed by the Bankruptcy Court at their litigated or settled level.

      The claims estimation procedures remain in place for use in the
      post-confirmation liquidation of those producer claims that remain
      unresolved. The claims mediator is holding evidentiary hearings with
      respect to individual producer claims, including claim-specific issues not
      addressed by the reports. Recommendations made by the claims mediator are
      subject to review by the Bankruptcy Court and all parties have rights of
      appellate review. When claims are allowed by the Bankruptcy Court and the
      allowances become final, Columbia Transmission will make distributions
      with respect to those claims pursuant to the Plan. The timing of this
      litigation process is impossible to predict. Based on the information
      received and evaluated to date, Columbia believes adequate reserves have
      been established for resolution of the remaining producer claims and the
      payment of any amounts which may ultimately become due to producers with
      respect to the 5% holdback.

C.    REORGANIZATION ITEMS. During 1995 and 1994, Columbia and Columbia
      Transmission have earned interest income on cash accumulated from the
      suspension of payments related to prepetition liabilities and incurred
      expenses associated with professional fees and other related services.
      Included in 1995 is approximately $47.7 million of expense for items
      related to emergence from bankruptcy and 1994 reflected additional expense
      of $40 million for adjustments to reserves for producer claim levels based
      on the Claims Mediator's Report.


                                       50
<PAGE>   51
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

      Listed below is a summary of Reorganization Items included in the income
      statements.



<TABLE>
<CAPTION>
($ in millions)                             1996    1995       1994
-------------------------------------------------------------------
<S>                                         <C>    <C>        <C> 
Interest income on accumulated cash           --    93.5       63.4
Professional fees and related expenses        --   (28.2)     (35.4)
Other reorganization items, net               --   (51.9)     (40.3)
-------------------------------------------------------------------
Reorganization Items, Net                     --    13.4      (12.3)
-------------------------------------------------------------------
</TABLE>

3.    REGULATORY MATTERS

      A.    In August 1995, Columbia Transmission filed with the Federal Energy
            Regulatory Commission (FERC) its first general rate case since 1991,
            requesting an increase in annual revenue of approximately $147
            million. Columbia Transmission also proposed to recover its net
            investment in gathering and certain gas processing facilities over a
            period of five years. The FERC authorized the new rates to be
            implemented on February 1, 1996, subject to refund. However, in an
            effort to reach a timely resolution of the issues included in the
            filing, Columbia Transmission agreed to collect only 75% of the
            requested rate increase for an interim period.

            In January 1997, the FERC administrative law judge presiding over
            the rate case certified to FERC a settlement filed on November 22,
            1996 by Columbia Transmission. The settlement, which is supported by
            all of Columbia Transmission's firm service customers, resolves
            rate, cost of service, unbundling and certain other issues in the
            case. It resolves issues in related filings as well, including the
            transfer of certain gathering facilities to Columbia Transmission's
            affiliate Columbia Natural Resources, Inc. The settlement also
            incorporates a revised version of a partial settlement filed by
            Columbia Transmission on August 30, 1996. That element of the
            settlement provides for the continued use of system-wide rates,
            commonly known as postage-stamp rates, in lieu of zone rates. Under
            the settlement, Columbia Transmission will not place a new rate case
            into effect prior to February 1, 2000. The issue relating to
            recovery of environmental costs has been scheduled for a second
            phase in the rate case proceeding and was not addressed in this
            settlement. Approval of the proposed settlement will not have a
            significant effect on the consolidated financial statements.

      B.    In its September 1993 Order on Columbia Transmission's and Columbia
            Gulf's FERC Order No. 636 (Order 636) compliance filings, the FERC
            initiated a proceeding concerning Columbia Gulf's transportation
            service to Columbia Transmission. It directed Columbia Gulf to show
            cause as to why it had not filed for FERC's abandonment
            authorization to reduce capacity on its mainline facilities. In a
            response to the FERC in late 1993, Columbia Gulf asserted that no
            abandonment authorization was required. During 1994 and early 1995,
            Columbia Transmission and Columbia Gulf responded to information
            requests from the FERC's staff. Management continues to believe that
            an abandonment filing was not necessary; however, the ultimate
            outcome of this issue is uncertain.

      C.    On March 1, 1995, Columbia Transmission filed with the FERC to
            recover $69 million of annual projected transportation costs and $39
            million of unrecovered transportation costs that were billed to
            Columbia Transmission by Columbia Gulf. Various parties protested
            Columbia Transmission's filing, and challenged among other things
            Columbia Transmission's ability to recover costs attributable to
            Columbia Gulf.

            In an April 2, 1996 Order, the FERC ruled that Columbia Gulf was
            entitled to bill its prudently incurred costs, under its
            cost-of-service tariff, to Columbia Transmission, and that Columbia
            Transmission was entitled to flow such amounts through to its
            customers. The FERC ruled that approximately $19 million of the
            Columbia Gulf charges, which were attributable to operation and
            maintenance costs, were recoverable, subject to a general FERC
            audit. With respect to the remaining $20 million of costs, that were
            associated with environmental issues, the FERC established hearing
            procedures to determine if any portion of these costs were not
            prudently incurred by Columbia Gulf and therefore would not be
            recoverable. A hearing on this issue is scheduled for the first
            quarter of 1997. FERC has denied requests for rehearing of the April
            1996 Order.


                                       51
<PAGE>   52
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

            While the outcome of the hearing is uncertain, management believes
            Columbia Transmission has a valid basis for recovering these costs.
            It is not expected that the outcome will have a material adverse
            impact on the company's financial statements.

      D.    In response to numerous petitions for review of Order 636, the D.C.
            Circuit Court of Appeals issued a decision in July 1996. The court
            generally upheld the FERC's actions, but remanded to the FERC
            certain aspects of Order 636. Motions for reconsideration of the
            court's order have been filed and responses made by the FERC and
            certain distribution companies. As a result of these proceedings,
            Order 636 may be modified or reversed in whole or in part; however,
            at this time it is impossible to predict the outcome. Columbia
            Transmission does not believe that the order will have a significant
            impact on its operations. A customer settlement approved by the FERC
            in 1995 provides that any relief granted as a result of the court
            decision will be implemented prospectively on Columbia
            Transmission's system, and that Columbia Transmission will have no
            refund obligation or other financial liability as a result of the
            decision.

      E.    On October 31, 1996, Columbia Gulf filed a general rate case with
            the FERC. The proposed rates would result in approximately $9.6
            million of additional annual revenue compared to the revenues
            generated by Columbia Gulf's current rates. The filed rates have
            been suspended by the FERC until May 1, 1997, when they may be
            placed into effect, subject to refund and conditions, pending the
            outcome of a hearing.

      F.    Columbia Gas of Ohio's (Columbia of Ohio) 1994 rate case settlement
            provided for a review of the company's revenue requirements by a
            collaborative group composed of diverse interested parties
            (Collaborative), for the purpose of evaluating the need to adjust
            base rates at May 1, 1996. The review process was completed and in
            October 1996, Columbia of Ohio filed an unopposed settlement with
            the Public Utilities Commission of Ohio (PUCO) to resolve its
            revenue requirement. This filing was approved by the PUCO in
            December 1996. The filing permits Columbia of Ohio to retain up to
            $51 million of revenues over the next three years subject to a
            sharing mechanism, under which a portion of any earnings above an
            industry composite allowed return on equity would be shared with
            customers. The revenues retained are primarily from historic
            off-system sales transactions completed or agreed to prior to August
            31, 1996. As allowed under this settlement, revenues of
            approximately $11.5 million were recorded in 1996 income with
            revenues eligible for retention in each of the following two years
            of approximately $19.7 million. This revenue mechanism is in lieu of
            a base rate increase and does not result in any base rate increase
            for customers. Additionally, the settlement provides that Columbia
            of Ohio will not implement any increase in base rates before January
            1, 1999.

4.    RESTRUCTURING ACTIVITIES

      The transmission subsidiaries began a reengineering project to assess the
      way the companies operate. These efforts are expected to streamline the
      business functions, improve the organizational structure and reduce staff
      levels. The project is focusing on all processes within the transmission
      subsidiaries. Additional expense is expected to be incurred in 1997.

      The distribution segment has initiated a restructuring of its
      headquarters' operation as part of its ongoing efforts to provide enhanced
      customer service and to achieve greater operating efficiencies. In
      addition, "Project Customer" initiatives which are designed to streamline
      and enhance customer service are continuing. Additional studies are
      underway in all of the distribution segment's service territories that may
      affect the field organizations in functions other than customer service
      and may result in additional positions being eliminated which will result
      in additional expense being recorded.

      The exploration and production segment reengineered its administrative
      operations to reduce overhead.

      In the third quarter of 1996, Columbia Gas System Service Corporation,
      Columbia LNG Corporation and TriStar Ventures Corporation implemented a
      reengineering program as well as moved their corporate headquarters from
      Wilmington, Delaware to Reston, Virginia.

      As a result of these restructuring programs, it is estimated that 1,105
      management, professional, administrative and technical positions will be
      eliminated. In 1996, Columbia recorded a pre-tax charge of $60.9 million
      in operating expense representing severance and related benefit costs,
      relocation costs, the establishment of the


                                       52
<PAGE>   53
    ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

            new corporate center and costs related to the sale of the
            headquarters building. This charge included $52.7 million of
            estimated termination benefits. Partially offsetting these charges
            is a $6 million pre-tax gain on the sale of the headquarters
            building. As of December 31, 1996, approximately 530 employees have
            been terminated as a result of these programs. The remaining accrual
            associated with the restructuring activities totaled $38.6 million
            at December 31, 1996.

    5.      COMMODITY HEDGING ACTIVITIES

            Subsidiaries in Columbia's production, marketing and propane
            operations engage in commodity hedging activities to minimize the
            risk of market fluctuations associated with the price of natural gas
            and crude oil production, propane inventories and commitments for
            natural gas purchases and sales. The hedging objectives include
            assurance of stable and known minimum cash flows, fixing favorable
            prices and margins when they become available and participation in
            any long-term increases in value. Under internal guidelines,
            speculative positions are prohibited.

            Columbia's exploration and production company utilizes futures,
            options and swaps on futures as well as commodity price swaps and
            basis swaps. Futures help manage commodity price risk by fixing
            prices for future production volumes. The options provide a price
            floor for future production volumes and the opportunity to benefit
            from any increases in prices. Swaps are negotiated and executed
            over-the-counter and are structured to provide the same risk
            protection as futures and options. Basis swaps are used to manage
            risk by fixing the basis or differential that exists between a
            delivery location index and the commodity futures prices. At
            December 31, 1996, there were 1,490 open contracts representing a
            notional quantity amounting to 14.9 Bcf of natural gas production
            through October of 1997, at an average price of $2.32 per Mcf. A
            total of $1.2 million of unrealized gains have been deferred on the
            consolidated balance sheet with respect to these open contracts. At
            December 31, 1995, there were 285 open contracts representing a
            notional quantity amounting to 2.9 Bcf of natural gas production
            through March of 1996. A total of $0.5 million of unrealized losses
            were deferred on the consolidated balance sheet with respect to
            those open contracts at December 31, 1995.

            During the year ended December 31, 1996, $3.7 million of losses were
            realized on the settlement of natural gas option and swap contracts
            entered into to hedge the value of gas production. During the year
            ended December 31, 1995, $6.8 million of gains were realized on the
            settlement of these contracts. These gains and losses are offset
            when the production is sold in the cash market.

            At December 31, 1996, there were 5,173 open contracts through
            October of 1998, representing a notional quantity amounting to 51.7
            Bcf of natural gas. A total of $0.8 million of realized gains have
            been deferred on the consolidated balance sheet with respect to
            these open contracts. At December 31, 1995, there were 482 open
            contracts through January 1997, representing a notional quantity
            amounting to 4.8 Bcf of natural gas. A total of $0.8 million of
            unrealized losses were deferred on the consolidated balance sheet
            with respect to these open contracts at December 31, 1995. These
            unrealized losses are offset by gains which are realized when the
            products are sold.

            Columbia's marketing and propane operations utilize futures
            contracts and basis swaps to assure adequate margins on the purchase
            and resale of natural gas as well as protecting the value and
            margins of its propane inventories. During the years ended December
            31, 1996 and 1995, losses of $6.3 million and $4.9 million,
            respectively, were recognized in operating income on the settlement
            of natural gas futures and basis swaps. Gains and losses on propane
            and gas marketing hedging activities were offset by amounts realized
            from the sale of the underlying products.

            Columbia and its subsidiaries are exposed to credit losses in the
            event of nonperformance by the counterparties to its various hedging
            contracts. Management has evaluated such risk and believes that
            overall business risk is minimized as a result of these hedging
            contracts which are primarily with major investment grade financial
            institutions or their affiliates.


                                       53
<PAGE>   54
    ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

    6. ACCOUNTING STANDARDS

       A.   As a result of emergence from bankruptcy and significant industry
            changes culminating with Order 636, the operating experience gained
            since implementation of Order 636, a Columbia Transmission rate case
            that was filed on August 1, 1995, and the resolution of gas contract
            difficulties and various customer issues, Columbia Transmission and
            Columbia Gulf reapplied SFAS No. 71 upon Columbia Transmission's
            emergence from bankruptcy. Management believes that cost of service
            rate concepts will continue to be applicable to Columbia's
            FERC-regulated transmission subsidiaries for the foreseeable future.
            The reapplication of SFAS No. 71 resulted in the recognition of
            regulatory assets for certain costs previously expensed, which are
            expected to be recovered in rates, mainly environmental and
            postemployment benefit costs, and recording revenues and expenses in
            a manner to reflect the rate making process. As a result of
            reapplying SFAS No. 71, an extraordinary gain of $71.6 million was
            recorded in 1995.

       B.   Effective January 1, 1994, Columbia adopted the Financial Accounting
            Standards Board's Statement of Financial Accounting Standards No.
            112, "Employers' Accounting for Postemployment Benefits." This
            statement requires employers to recognize obligations to provide
            benefits to former or inactive employees after employment, but
            before retirement. Such benefits include, but are not limited to,
            salary continuation, supplemental unemployment, severance,
            disability, job training, counseling, and continuation of benefits
            such as health care and life insurance coverage.

            The adoption of this statement resulted in an accrual of $14.4
            million of which $5.6 million was deferred by certain of the
            distribution subsidiaries as a regulatory asset pending rate
            recovery authorization from their respective state commissions. The
            after-tax effect of the remainder reduced 1994 net income by $5.6
            million.

       C.   On January 1, 1996, Columbia adopted the Financial Accounting
            Standards Board's Statement of Financial Accounting Standards No.
            121, "Accounting for the Impairment of Long-Lived Assets and for
            Long-Lived Assets to Be Disposed Of" (SFAS No. 121). This statement
            establishes accounting standards for the impairment of long-lived
            assets, certain identifiable intangibles, and goodwill related to
            those assets to be held and used and for long-lived assets and
            certain identifiable intangibles to be disposed of. SFAS No. 121
            requires these assets be reviewed for possible impairment whenever
            events or changes in circumstances indicate that the carrying amount
            may not be recoverable. The adoption of SFAS No. 121 did not have a
            material impact on Columbia's financial statements.


                                       54
<PAGE>   55
    ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

    7. INCOME TAXES

            The components of income tax expense are as follows:


<TABLE>
<CAPTION>
Year Ended December 31 ($ in millions)                           1996     1995       1994
                                                                -----    ------     -----
<S>                                                             <C>      <C>         <C>
INCOME TAXES
Current
      Federal                                                    30.4    (284.8)     63.8
      State                                                       7.5       8.1      10.0
                                                                -----    ------     -----
Total Current                                                    37.9    (276.7)     73.8
                                                                -----    ------     -----
Deferred
      Federal                                                    64.6      69.7      78.9
      State                                                      14.9      (2.2)     (5.3)
                                                                -----    ------     -----
Total Deferred                                                   79.5      67.5      73.6
                                                                -----    ------     -----
   Deferred Investment Credits                                   (1.5)     (1.5)     (1.4)
                                                                -----    ------     -----
Income taxes included in income before extraordinary
  item and cumulative effect of accounting change               115.9    (210.7)    146.0
Deferred taxes related to extraordinary item and
  cumulative effect of accounting change                            -      36.9      (3.3)
                                                                -----    ------     -----
TOTAL INCOME TAXES                                              115.9    (173.8)    142.7
                                                                -----    ------     -----
</TABLE>

Total income taxes are different from the amount that would be computed by
applying the statutory Federal income tax rate to book income before income tax.
The major reasons for this difference are as follows:


<TABLE>
<CAPTION>
Year Ended December 31 ($ in millions)                  1996                 1995                1994
                                                        -----               ------               -----
<S>                                                     <C>         <C>     <C>         <C>      <C>        <C>
   Book income (loss) before income taxes,
      extraordinary item and cumulative effect of
      accounting change                                 337.5               (643.0)              392.2
   Tax expense (benefit) at statutory                   
      Federal income tax rate                           118.1       35.0%   (225.0)     35.0%    137.3      35.0%
   Increases (reductions) in taxes resulting from:
   State income taxes, net of Federal
      income tax benefit                                 16.7        4.9       4.7      (0.7)      2.6       0.6
   Estimated non-deductible expenses                      0.9        0.3       9.0      (1.4)      6.4       1.6
   Effect of change in deferred taxes
      previously provided                                (4.0)      (1.2)        -         -         -         -
   Adjustment to prior years' tax provision due
       to pending settlement                            (11.3)      (3.4)        -         -         -         -
   Other                                                 (4.5)      (1.3)      0.6      (0.1)     (0.3)        -
                                                        -----       ----    ------      ----     -----      ---- 
INCOME TAXES BEFORE EXTRAORDINARY
    ITEM AND CUMULATIVE EFFECT OF                       
    ACCOUNTING CHANGE                                   115.9       34.3%   (210.7)     32.8%    146.0      37.2%
                                                        =====       ====    ======      ====     =====      ==== 
</TABLE>


                                       55
<PAGE>   56
    ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)


<TABLE>
<CAPTION>
Deferred tax balances are as follows:
At December 31 ($ in millions)                              1996            1995
                                                            -----           -----
<S>                                                         <C>             <C>  
  Net current liabilities (assets)
      Federal                                               (53.8)          (30.9)
      State                                                   1.0            (6.2)
                                                            -----           -----
Total                                                       (52.8)          (37.1)
                                                            -----           -----
  Net noncurrent liabilities
      Federal                                               481.9           401.6
      State                                                  75.8            67.0
                                                            -----           -----
  Total                                                     557.7           468.6
                                                            -----           -----
TOTAL DEFERRED INCOME TAXES                                 504.9           431.5
                                                            -----           -----
</TABLE>

Deferred income taxes result from temporary differences between the financial
statement carrying amounts and the tax basis of existing assets and liabilities.
The source of these differences and tax effect of each is as follows:


<TABLE>
<CAPTION>
At December 31 ($ in millions)                              1996*           1995
                                                            -----           -----
<S>                                                         <C>             <C>  
Property basis differences                                  584.0           610.5
Gas purchase costs                                           94.4            15.1
Transportation costs                                          -               2.0
Partnership deferrals                                        23.9            26.0
Deferred revenue                                             (5.5)           (0.9)
Estimated supplier obligations                              (60.8)          (59.6)
Estimated rate refunds                                      (25.0)          (13.1)
Postretirement benefits                                     (16.5)          (17.0)
Environmental liabilities                                     2.1           (17.2)
Capitalized inventory overheads                             (24.3)          (25.5)
Unbilled utility revenue                                    (23.9)          (12.5)
Net operating loss carryforward                               -             (19.9)
Alternative minimum tax                                     (46.9)          (91.0)
Debt forgiveness                                             47.5            50.7
Restructuring costs                                         (18.5)           (5.2)
Other                                                       (25.6)          (10.9)
                                                            -----           -----
TOTAL DEFERRED INCOME TAXES                                 504.9           431.5
                                                            -----           -----
</TABLE>

*  At December 31, 1996, Columbia had state income tax net operating loss
   carryforwards (net of federal taxes) of approximately $40,100,000. The
   realization of such state income tax carryforwards is dependent upon
   generating sufficient taxable income prior to their expiration. Management
   believes that there is a risk that certain of these carryforwards may expire
   unused and, therefore, an asset has not been recorded for such future
   benefits. The expiration of the state tax loss carryforward benefits, net of
   federal taxes, in 1997 is $0.4 million, in 1988 is $0.5 million, in 1999 is
   $2.8 million, in 2000 is $1.6 million, in 2001 is $0.6 million, and beyond is
   $34.2 million.


                                       56
<PAGE>   57
    ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

    8. PENSION AND OTHER POSTRETIREMENT BENEFITS

       A. PENSION PLANS. Columbia has a noncontributory, qualified defined
       benefit pension plan covering essentially all employees. Benefits are
       based primarily on years of credited service and employees' highest
       three-year average annual compensation in the final five years of
       service. Columbia's funding policy complies with Federal law and tax
       regulations.

       Columbia also has a nonqualified pension plan that provides benefits to
       some employees in excess of the qualified plan's Federal tax limits.

       Effective 1996, Columbia is reflecting the information presented below
       as of September 30, rather than December 31. The effect of this change
       is not material.

       The following table shows the components of net pension expense for the
       qualified and nonqualified plans and the annual contributions for each
       of the three years:


<TABLE>
<CAPTION>
PENSION COSTS ($ in millions)                    1996          1995         1994
                                                 -----        ------        ----- 
<S>                                              <C>          <C>           <C> 
Service cost                                      35.0          26.7         34.2
Interest cost                                     70.7          69.9         68.8
Actual return on assets                          (81.9)       (202.5)       (11.3)
Net amortization (deferral)                       (5.1)        124.8        (66.1)
                                                 -----        ------        ----- 
NET PENSION EXPENSE                               18.7          18.9         25.6
                                                 -----        ------        ----- 
CONTRIBUTIONS                                      0.0           1.2          7.0
                                                 -----        ------        ----- 
</TABLE>

The following table provides a reconciliation of the plans' funded status and
amounts reflected in columbia's balance sheet at December 31:


<TABLE>
<CAPTION>
PLAN ASSETS AND OBLIGATIONS ($ in millions)                  1996         1995
                                                            -------      -------
<S>                                                         <C>          <C>    
Plan assets at fair value                                   1,033.9      1,034.6
                                                            -------      -------
Actuarial present value of benefit obligations:
   Vested benefits                                            660.6        760.2
   Nonvested benefits                                          48.7         56.1
                                                            -------      -------
Accumulated benefit obligation                                709.3        816.3
Effect of projected future salary increases                   160.6        190.8
                                                            -------      -------
PROJECTED BENEFIT OBLIGATION                                  869.9      1,007.1
                                                            -------      -------
Plan assets in excess of projected benefit obligation         164.0         27.5
Unrecognized net gain                                        (281.5)      (131.8)
Unrecognized prior service cost                                52.6         56.5
Unrecognized transition obligation                              7.0          8.1
                                                            -------      -------
ACCRUED PENSION COST                                          (57.9)       (39.7)
                                                            -------      -------
DISCOUNT RATE ASSUMPTION                                        8.0%         7.0%
                                                            -------      -------
COMPENSATION GROWTH RATE ASSUMPTION                             5.0%         5.0%
                                                            -------      -------
ASSET EARNINGS RATE ASSUMPTION                                  9.0%         9.0%
                                                            -------      -------
</TABLE>

Plan assets consist of primarily equity (international and domestic) and fixed
income securities.

As of December 31, 1996, the discount rate assumption was revised upward to
8.0%. The net effect of this change was to decrease the accumulated benefit
obligation and the projected benefit obligation by $88.3 million and $127.5
million, respectively.


                                       57
<PAGE>   58
    ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

        B. OTHER POSTRETIREMENT BENEFITS. Columbia also provides medical
        coverage and life insurance to retirees. Essentially all active
        employees are eligible for these benefits upon retirement after
        completing ten consecutive years of service after age 45. Normally,
        spouses and dependents of retirees are also eligible for medical
        benefits.

        Effective 1996, Columbia is reflecting the information presented below
        as of September 30 rather than December 31. The effect of this change is
        not material.

        The following table shows components of other postretirement costs for
        each of the three years:


<TABLE>
<CAPTION>
OTHER POSTRETIREMENT COSTS ($ in millions)          1996        1995         1994
                                                    -----       -----        ---- 
<S>                                                 <C>         <C>          <C> 
Service cost                                         13.8        11.3        15.3
Interest cost                                        22.4        24.1        24.6
Actual return on assets                             (12.5)      (30.0)       (2.1)
Other, net amortization (deferral)                   (5.4)       16.0        (4.9)
                                                    -----       -----        ---- 
OTHER POSTRETIREMENT COSTS, NET                      18.3        21.4        32.9
                                                    -----       -----        ---- 
CONTRIBUTIONS                                        36.2        41.8        20.7
                                                    -----       -----        ---- 
</TABLE>


The following table provides a reconciliation of other postretirement plans'
funded status and amounts reflected on Columbia's balance sheet at December 31:


<TABLE>
<CAPTION>
PLAN ASSETS AND OBLIGATIONS ($ in millions)                    1996       1995
                                                              ------     ------- 
<S>                                                           <C>        <C>
Accumulated postretirement benefit obligation:
Retirees                                                       151.0       172.1
Fully eligible active plan participants                         54.5        60.5
Other participants                                              81.7        83.2
                                                              ------     ------- 
Total accumulated postretirement benefit obligation            287.2       315.8
Plan assets at fair value                                     (179.6)     (149.1)
                                                              ------     ------- 
Accumulated postretirement benefit obligation
    in excess of plan assets                                   107.6       166.7
Unrecognized actuarial net gain                                117.5        72.8
Less: Fourth quarter contributions                               6.6         -
                                                              ------     ------- 
ACCRUED POSTRETIREMENT BENEFIT COST                            218.5       239.5
                                                              ------     ------- 
DISCOUNT RATE ASSUMPTION                                         8.0%        7.0%
                                                              ------     ------- 
MEDICAL COST TREND                                               5.5%    8.0-5.5%
                                                              ------     ------- 
COMPENSATION GROWTH RATE ASSUMPTION                              5.0%        5.0%
                                                              ------     ------- 
ASSET EARNINGS RATE ASSUMPTION*                                  9.0%        9.0%
                                                              ------     ------- 
</TABLE>

*One of the several established medical trusts is subject to taxation which
results in an after-tax asset earnings rate that is less than 9%.

Plan assets consist of shares in various equity (international and domestic) and
fixed income mutual funds. The assets are held in three trust accounts and one
401(h) account.

As of December 31, 1996, the discount rate assumption was revised upward to 8.0%
from 7.0%. The medical cost trend rate at December 31, 1996 was 5.5%, a change
from the December 31, 1995 rate which started at 8.0% and decreased to 5.5%
after six years. The net effect of these changes was a $50.9 million decrease in
the accumulated postretirement benefit obligation. A one percent increase in
medical inflation trend rates for each future year would have increased the
accumulated postretirement benefit obligation by another $16.2 million and other
postretirement costs by $3.0 million in 1996.

All of Columbia's subsidiaries participate in funding for retiree life insurance
benefits, using a voluntary employee beneficiary association (VEBA) trust.
Columbia's funding policy is to make annual contributions to this trust, subject
to the maximum tax-deductible limit. Contributions of approximately $3.3
million, and $3.8 million were made to the retiree life insurance VEBA trust in
1996 and 1995, respectively.


                                       58
<PAGE>   59
    ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

        9. LONG-TERM INCENTIVE PLAN

        On April 26, 1996, shareholders approved a new Long-Term Incentive Plan
        (New LTIP). The New LTIP which is effective for ten years, beginning
        February 21, 1996, provides for the granting of nonqualified stock
        options and incentive stock options, contingent stock awards, stock
        appreciation rights and restricted stock awards to officers and key
        employees. The New LTIP also provides for the granting of nonqualified
        stock options to outside directors. A total of 3,000,000 shares of
        Columbia's authorized common stock is available under the New LTIP's
        provisions.

        On April 26, 1996, shareholders approved an incentive compensation plan
        for outside directors under which they may receive benefits in lieu of a
        retirement plan and defer current compensation in the form of phantom
        stock units, which equates the amounts granted to the directors with the
        performance of Columbia's stock.

        Columbia's Long-Term Incentive Plan (LTIP), in effect from 1985 through
        1995, provided for the granting of nonqualified stock options, stock
        appreciation rights and contingent stock awards as determined by the
        Compensation Committee of the Board of Directors. That committee also
        had the right to modify any outstanding award. A total of 1,500,000
        shares of Columbia's authorized common stock was initially reserved for
        issuance under the LTIP's provisions.

        Stock appreciation rights, which were granted in connection with certain
        nonqualified stock options, entitle the holders to receive stock, cash
        or a combination thereof equal to the excess market value over the grant
        price. Stock options and related stock appreciation rights granted under
        the LTIP generally have a maximum term of ten years and vest over two to
        four years.


        Transactions for the three years ended December 31, 1996, are as
        follows:

<TABLE>
<CAPTION>
                                           Options
                                 ---------------------------
                                 Without Stock   With Stock           Option
                                 Appreciation   Appreciation          Price
                                    Rights         Rights             Range
                                   --------        -------       ---------------
<S>                                <C>             <C>           <C>  
Outstanding 12/31/93                505,620        156,150       $  34.30-$46.68
                                   --------        -------       ---------------
  1994
  Cancelled                         (20,655)             -       $  34.30-$46.68
  Outstanding 12/31/94              484,965        156,150       $  34.30-$46.68
                                   --------        -------       ---------------
  1995
  Granted                            93,000              -       $  28.99-$31.05
  Exercised                         (33,245)        (6,100)      $  28.99-$38.30
  Cancelled                         (20,400)             -       $  34.30-$46.68
  Outstanding 12/31/95              524,320        150,050       $  28.99-$46.68
                                   --------        -------       ---------------
  1996
  Granted                           100,000              -       $       48.6875
  Exercised                        (209,625)       (66,860)      $  28.99-$46.68
  Forfeited                          (9,020)        (7,260)      $  34.30-$46.68
                                   --------        -------       ---------------
OUTSTANDING 12/31/96                405,675         75,930       $28.99-$48.6875
                                   --------        -------       ---------------
EXERCISABLE 12/31/96                355,675         75,930       $28.99-$48.6875
                                   --------        -------       ---------------
</TABLE>


                                       59
<PAGE>   60
    ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

The following table shows the weighted average option exercise price information
for the two years ended December 31:

<TABLE>
<CAPTION>
                                                           1996           1995
                                                         -------        -------
<S>                                                      <C>            <C>    
Outstanding at January 1                                 $ 41.31        $ 42.69
Granted during the year                                    48.69          29.10
Exercised during the year                                  41.07          35.36
Forfeited during the year                                  44.15              -
Cancelled during the year                                      -          40.61
OUTSTANDING AT DECEMBER 31                                 42.88          41.31
EXERCISABLE AT DECEMBER 31                                 42.21          41.31
                                                         -------        -------
</TABLE>


        In addition to the options, contingent stock awards totaling 27,500
        shares were issued to two key executives in 1995. As of December 31,
        1996, the equivalent of 22,500 of these shares have vested, 20,160
        shares have been issued (net of amounts withheld to pay taxes), and
        5,000 shares remain outstanding. During 1996, contingent stock awards
        totaling 1,500 shares were issued to one key executive. As of December
        31, 1996, all 1,500 shares have vested and been issued. Restricted stock
        awards totaling 29,785 shares were issued to one key executive in 1996.
        As of December 31, 1996, all 29,785 shares remain outstanding.

        During 1996 and 1995, $1.5 million and $1.1 million were expensed for
        the Long-Term Incentive Plan, respectively. There were de minimus
        amounts expensed for the Long-Term Incentive Plan in 1994.

        Had compensation cost been determined consistent with the provisions of
        the SFAS No. 123 fair value method (See Note 1N), the effect on
        Columbia's net income and earnings per share for both 1996 and 1995
        would have been immaterial. Regarding the stock options issued in 1995,
        100% of such options vested in 1995. Regarding the stock options issued
        in 1996, 50% of such options vested in 1996 and the other 50% will vest
        in 1997. The fair value of each option grant is estimated on the date of
        grant using the Black-Scholes option-pricing model with the following
        weighted assumptions used for grants in 1995 and 1996: dividend yield of
        1.18%; expected volatility of 20.12%; risk free interest rate of 6.39%
        and 5.93% for 1995 and 6.58% for 1996; and expected lives of seven
        years.


    10. PREFERRED STOCK

        Columbia has authorized 40,000,000 shares of preferred stock with a par
        value of $10 per share. As of December 31, 1995, Columbia had
        outstanding 7,999,494 shares of 7.89% Series A-Preferred Stock and
        4,898,946 shares of 5.22% Series B-DECS. The Series A - Preferred Stock
        was issued at $25 per share and with an aggregate liquidation value of
        $199,987,350. The Series B - DECS was issued at $40.82 per share with an
        aggregate liquidation value of $199,974,975.

        On February 26, 1996, Columbia redeemed all outstanding shares of its
        two series of preferred stock at the liquidating value. As a result, no
        dividends were paid on preferred stock during 1996.


                                       60
<PAGE>   61
    ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)


    11. LONG-TERM DEBT

    The long-term debt (exclusive of current maturities) of Columbia and its
    subsidiaries is as follows:

<TABLE>
<CAPTION>
At December 31 ($ in millions)                                1996          1995
                                                             -------       -------
<S>                                                          <C>           <C>
The Columbia Gas System, Inc. 
Debentures
      6.39% Series A due November 28, 2000                     311.0         311.0
      6.61% Series B due November 28, 2002                     281.5         281.5
      6.80% Series C due November 28, 2005                     281.5         281.5
      7.05% Series D due November 28, 2007                     281.5         281.5
      7.32% Series E due November 28, 2010                     281.5         281.5
      7.42% Series F due November 28, 2015                     281.5         281.5
      7.62% Series G due November 28, 2025                     281.5         281.5
                                                             -------       -------
Total Debentures                                             2,000.0       2,000.0

Subsidiary Debt:
Capitalized lease obligations                                    2.5           2.9
Other                                                            1.3           1.6
                                                             -------       -------
TOTAL LONG-TERM DEBT                                         2,003.8       2,004.5
                                                             -------       -------
</TABLE>

The aggregate maturities of long-term debt and capitalized lease obligations
during the next five years are as follows:


<TABLE>
<CAPTION>
($ in millions)
<C>                                                                          <C>
1997                                                                           0.9
1998                                                                           0.5
1999                                                                           0.5
2000                                                                         311.4
2001                                                                           0.6
</TABLE>
    
    12. SHORT-TERM DEBT AND CREDIT FACILITIES

        Effective November 1995, Columbia entered into an unsecured bank
        revolving credit agreement (Credit Facility). The Credit Facility
        consists of a five year revolving credit agreement maturing November
        2000. The Credit Facility has an initial commitment amount of $1 billion
        with scheduled quarterly commitment reductions of $25 million beginning
        on December 31, 1997. Interest rates on borrowings are based upon the
        London Interbank Offered Rate, Certificate of Deposit rates or other
        short-term interest rates. Compensating balances are not required.
        Columbia is required to pay a facility fee on the commitment amount at a
        rate which is based on Columbia's public debt rating. The facility fee
        rate as of December 31, 1996 is 0.14%. The Credit Facility contains
        certain covenants that must be met to borrow funds including
        restrictions on the incurrence of liens, a maximum leverage ratio, and a
        minimum consolidated net worth. At December 31, 1996, Columbia had
        outstanding $250 million under the Credit Facility at an average rate of
        6.44%. At December 31, 1995, Columbia had outstanding $338.9 million
        under the Credit Facility at an average rate of 6.46%. The maximum
        indebtedness outstanding during the year occurred on March 5, 1996 in
        the amount of $652.1 million at an interest rate of 5.88%.

        The Credit Facility provides for the issuance of up to $100 million of
        standby letters of credit. In addition, at the option of Columbia, an
        additional $50 million of the credit facility can be utilized for
        letters of credit or borrowings. As of December 31, 1996, Columbia had
        $86.8 million of letters of credit outstanding under the 


                                       61
<PAGE>   62
    ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

        Credit Facility. Fees for letters of credit issued are calculated at
        rates that are based on Columbia's public debt rating plus a commission
        of 0.125% to the issuing bank. At December 31, 1996, fees for letters of
        credit issued in connection with certain financial obligations were at a
        rate of 0.2775%.

    13. FAIR VALUE OF FINANCIAL INSTRUMENTS

        Statement of Financial Accounting Standards No. 107, "Disclosures about
        Fair Value of Financial Instruments" extends existing fair value
        disclosure practices by requiring all entities to disclose the fair
        value of financial instruments, both assets and liabilities, recognized
        and not recognized in the consolidated balance sheets, for which it is
        practicable to estimate a fair value. For purposes of this disclosure,
        the fair value of a financial instrument is the amount at which the
        instrument could be exchanged in a current transaction between willing
        parties, other than in a forced or liquidation sale. Fair value may be
        based on quoted market prices for the same or similar financial
        instruments or on valuation techniques, such as the present value of
        estimated future cash flows using a discount rate commensurate with the
        risks involved.

        The following methods and assumptions were used to estimate the fair
        value of each class of financial instruments for which it is practicable
        to estimate that value:

        Long-term investments

        Long-term investments include loans receivable ($4.0 million for 1996
        and $3.9 million for 1995) whose estimated fair values are based on the
        present value of estimated future cash flows using an estimated rate for
        similar loans. Also, included in 1995 was an income tax refund
        receivable with associated interest of $80.1 million whose carrying
        amount approximated fair value. The financial instruments included in
        long-term investments are primarily reflected in Investments and Other
        Assets in the consolidated balance sheets.

        Long-term debt

        The estimated fair value of Columbia's debentures, including accrued
        interest, is based on estimates provided by brokers.


<TABLE>
<CAPTION>
                                                               1996                  1995
                                                        ------------------    ------------------
                                                       CARRYING     FAIR     CARRYING     FAIR
AT DECEMBER 31 ($ IN MILLIONS)                          AMOUNT      VALUE     AMOUNT      VALUE
                                                        -------    -------    -------    -------
<S>                                                     <C>        <C>        <C>        <C>
LONG-TERM INVESTMENTS FOR WHICH IT IS:
      PRACTICABLE TO ESTIMATE FAIR VALUE                    4.0        3.6       84.0       83.6
            NOT PRACTICABLE TO ESTIMATE FAIR VALUE          4.2          -        6.6        -
LONG-TERM DEBT                                          2,012.9    1,948.1    2,012.9    2,044.7
                                                        -------    -------    -------    -------
</TABLE>

As cash and temporary cash investments, current receivables, current payables,
and certain other short-term financial instruments are all short-term in nature,
their carrying amount approximates fair value.

    14. OTHER COMMITMENTS AND CONTINGENCIES

        A.  CAPITAL EXPENDITURES. Capital expenditures for 1997 are currently
            estimated at $490 million. Of this amount, $267 million is for
            transmission and storage operations, $160 million for distribution
            operations, $39 million for exploration and production operations,
            $10 million for marketing, propane and power generation operations
            and $14 million for Corporate.

        B.  OTHER LEGAL PROCEEDINGS. Columbia and its subsidiaries have been
            named as defendants in various legal proceedings. In the opinion of
            management, the ultimate disposition of these currently asserted
            claims will not have a material adverse impact on Columbia's
            consolidated financial position or results of operations.


                                       62
<PAGE>   63
    ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

        C.  ASSETS UNDER LIEN. Substantially all of Columbia Transmission's
            properties have been pledged to Columbia as security for debt owed
            by Columbia Transmission to Columbia.

            TriStar Ventures Corporation (TriStar), a wholly-owned subsidiary of
            Columbia, is a general partner in the Binghamton, Pedericktown, and
            Vineland Cogeneration partnerships. All monies paid and to be paid
            by the partners are assigned as collateral for loans to various
            banks (or in the case of Vineland, to the Indenture Trustee).
            TriStar's investment in the partnerships, as of December 31, 1996,
            amounted to $29.1 million.

        D.  INTERNAL REVENUE SERVICE (IRS) AUDIT. A review by the IRS of
            Columbia's 1991 through 1994 federal income tax returns has been
            concluded. The major unresolved issues are included in the Revenue
            Agents Report, the resolution of which is currently being pursued
            with the Appeals Division of the IRS. Management believes that these
            same items will also be issues in the 1995 tax return. Based on the
            facts known at this time, management believes adequate reserves have
            been established for these issues.

        E.  OPERATING LEASES. Payments made in connection with operating leases
            are charged to operation and maintenance expense as incurred. Such
            amounts were $60.9 million in 1996, $61.6 million in 1995 and $56.6
            million in 1994.

            Future minimum rental payments required under operating leases that
            have initial or remaining noncancellable lease terms in excess of
            one year are:


<TABLE>
<CAPTION>
($ in millions)
<S>                                                                          <C> 
1997                                                                          26.3
1998                                                                          25.7
1999                                                                          24.8
2000                                                                          19.2
2001                                                                          17.4
After                                                                        208.5
</TABLE>

        F.  ENVIRONMENTAL MATTERS. Columbia's subsidiaries are subject to
            extensive federal, state and local laws and regulations relating to
            environmental matters. These laws and regulations, which are
            constantly changing, require expenditures for corrective action at
            various operating facilities, waste disposal sites and former gas
            manufacturing sites for conditions resulting from past practices
            that have subsequently become subject to environmental regulation.

            A subsidiary has received notice from the United States
            Environmental Protection Agency (EPA) that they are among several
            parties responsible under federal law for placing wastes at
            Superfund sites and may be required to share in the cost for
            remediation of these sites. However, considering known facts,
            existing laws and possible insurance and rate recoveries, management
            does not believe the identified Superfund matters will have a
            material adverse effect on future annual income or on Columbia's
            financial position.

            Columbia's transmission subsidiaries have implemented programs to
            continually review compliance with existing environmental standards.
            In addition, Columbia Transmission continues to review past
            operational activities and to formulate remediation programs where
            necessary. Columbia Transmission is currently conducting assessment,
            characterization and remediation activity of specific sites under a
            1995 EPA Administrative Order by Consent (AOC).

            In 1995, Columbia Transmission estimated that the cost of its
            environmental program under the AOC may range between $204 million
            and $319 million over the life of the program. This estimate was
            based on a limited amount of actual data available and utilized a
            variety of assumptions, including: the number of sites to be
            investigated, characterized and remediated; the location, nature and
            levels of wastes that will be treated at or disposed of from each
            site; the amount of time and nature of equipment required for such
            activities; the 


                                       63
<PAGE>   64
    ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

            appropriate remediation levels and the technology to be utilized;
            and the frequency with which groundwater contamination might be
            discovered at sites requiring remediation. The estimate did not
            include previously identified costs for certain specific activities,
            aggregating approximately $50 million, for which Columbia
            Transmission already had reasonable estimates.

            Following an extensive review of assumptions utilized in arriving at
            the estimate, management has concluded that only those site
            investigation, characterization and remediation costs currently
            known and determinable can be considered "probable and reasonably
            estimable" under Statement of Financial Accounting Standards No. 5,
            "Accounting for Contingencies" (SFAS No. 5). This conclusion was
            based upon the fact that the actual characterization and remediation
            experience of Columbia Transmission was extremely limited and
            information on environmental conditions at many of the sites or
            former sites of operations is not yet available. The nature and
            condition of such sites varies greatly, and any change in any of the
            numerous assumptions used in the estimate may materially alter the
            estimated range of costs, with no assurance that actual costs will
            not exceed amounts specified in the range. Columbia Transmission is
            unable, at this time, to accurately estimate the time frame and
            potential costs of all site screening, characterization and
            remediation. As Columbia Transmission continues its program pursuant
            to the AOC and additional costs become probable and reasonably
            estimable, the associated reserves will be adjusted as appropriate.
            Moreover, in time, management expects that, as additional work is
            performed and more facts become available, it will then be able to
            develop a probable and reasonable estimate for the entire program or
            a major portion thereof consistent with U. S. Securities and
            Exchange Commission's Staff Accounting Bulletin No. 92, SFAS No. 5
            and American Institute of Certified Public Accountants Statement of
            Position 96-1.

            Activities under the AOC in 1996 were focused on obtaining EPA
            approval to begin the assessment and characterization of certain
            major facilities, some select liquid removal points, and other
            select mercury measurement stations. In 1996, the EPA authorized
            Columbia Transmission to begin characterization of twelve major
            facilities. Columbia Transmission expects EPA approval to begin
            characterization of an additional 60 major facilities in 1997.

            Columbia Transmission also continued to conduct assessment and
            remediation of impacted soils at locations prior to normal
            construction and maintenance activities under its EPA approved
            Construction and Operation Work Plan (COWP). In 1996, Columbia
            Transmission conducted assessments at 216 sites and based on these
            assessment results, performed remedial activities in varying degrees
            at approximately 100 locations.

            As a result of these 1996 activities, Columbia Transmission recorded
            an additional liability of $3.3 million in the fourth quarter of
            this year and $2.5 million in the second quarter of this year.
            Actual expenditures of approximately $17 million during 1996 charged
            to the liability plus additions of nearly $6 million mentioned above
            resulted in a remaining overall liability of $126 million. Columbia
            Transmission's environmental cash expenditures are expected to be
            approximately $18 million in 1997 and continue annually at that
            level for the foreseeable future. These expenditures will be charged
            against Columbia Transmission's previously recorded liability.
            Management does not believe that Columbia Transmission's
            environmental expenditures will have a material adverse effect on
            its operations, liquidity or financial position, based on known
            facts and existing laws and regulations and the long period over
            which expenditures will be made. In addition, as a result of
            reapplying SFAS No. 71 in 1995, a regulatory asset has been recorded
            to the extent environmental expenditures are expected to be
            recovered through rates. Columbia Transmission is also currently
            involved in pursuing recovery of environmental expenditures from its
            insurance carriers. At this time, management is unable to determine
            the extent, if any, of recovery.

            In addition, predecessor companies of Columbia Transmission may have
            been involved in the operation of manufactured gas plants. When such
            plants were abandoned, material used and created in the process was
            sometimes buried at the site. From its investigations, Columbia
            Transmission is unable at this time to determine if it will become
            liable for any characterization or remediation costs at such sites.

            The distribution subsidiaries' (Distribution) primary environmental
            issues relate to 15 former manufactured gas plant sites.
            Investigations or remedial activities are currently underway at six
            sites and additional site investigations may be required at some of
            the remaining sites. To the extent Distribution site investigations
            have been conducted, remediation plans developed and any
            responsibility for remediation action established, the 


                                       64
<PAGE>   65
    ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

            appropriate liabilities have been recorded. Regulatory assets have
            also been recorded for a majority of these identified liabilities as
            rate recovery has been allowed or is anticipated.

            On October 18, 1995, Columbia of Pennsylvania was served in a
            Comprehensive Environmental Response Compensation and Liability Act
            cost recovery action related to the Keystone Sanitation Company
            Landfill/Superfund site. Columbia of Pennsylvania believes based on
            a preliminary investigation of the facts, that involvement at this
            site, if any, will not have a material impact on Columbia.

            The eventual total cost of full future environmental compliance for
            Columbia is difficult to estimate due to, among other things: (1)
            the possibility of as yet unknown contamination, (2) the possible
            effect of future legislation and new environmental agency rules, (3)
            the possibility of future litigation, (4) the possibility of future
            designations as a potential responsible party by the EPA and the
            difficulty of determining liability, if any, in proportion to other
            responsible parties, (5) possible insurance and rate recoveries, and
            (6) the effect of possible technological changes relating to future
            remediation. However, reserves have been established based on
            information currently available which resulted in a total recorded
            net liability of approximately $129 million for Columbia at December
            31, 1996. As new issues are identified, additional liabilities will
            be recorded.

            It is management's continued intent to address environmental issues
            in cooperation with regulatory authorities in such a manner as to
            achieve mutually acceptable compliance plans. However, there can be
            no assurance that fines and penalties will not be incurred.
            Management expects most environmental assessment and remediation
            costs to be recoverable through rates.

    15. INTEREST INCOME AND OTHER, NET


<TABLE>
<CAPTION>
Year Ended December 31 ($ in millions)               1996       1995          1994
                                                     ----       -----         ----
<S>                                                  <C>        <C>           <C> 
Interest income                                      13.4        22.8         31.8
Sale of Columbia Development                          6.9       (77.8)         -
Miscellaneous                                         5.8        (3.2)         3.4
                                                     ----       -----         ----
TOTAL                                                26.1       (58.2)        35.2
                                                     ----       -----         ----
</TABLE>


                                       65
<PAGE>   66
    ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)


    16. INTEREST EXPENSE AND RELATED CHARGES

<TABLE>
<CAPTION>
Year Ended December 31 ($ in millions)                    1996       1995      1994
                                                          -----      -----     ----
<S>                                                       <C>        <C>       <C>
Interest on emergence, including amortization of
   discounts on long-term debt                                -      982.9        -
Interest on long-term debt                                140.4          -        -
Interest on short-term debt                                11.7       15.1      0.2
Interest on rate refunds                                    3.9       17.7      9.0
Interest on prior years' taxes                              8.3       17.6     (8.8)
Allowance for borrowed funds used and interest
   during construction                                      2.5      (52.4)       -
Other interest charges                                        -        7.5     14.4
                                                          -----      -----     ----
TOTAL                                                     166.8      988.4     14.8
                                                          -----      -----     ----
</TABLE>


    17. BUSINESS SEGMENT INFORMATION

        Columbia is a registered holding company under the Public Utility
        Holding Company Act of 1935, as amended and derives substantially all of
        its revenues and earnings from the operating results of its 18 direct
        subsidiaries. Columbia's subsidiaries are divided into four primary
        business segments. The transmission and storage segment offers
        transportation, storage and gas peaking services for local distribution
        companies and industrial and commercial customers located in
        northeastern, middle Atlantic, midwestern, and southern states and the
        District of Columbia. The distribution segment provides natural gas for
        service for residential, commercial and industrial customers in Ohio,
        Pennsylvania, Virginia, Kentucky and Maryland. The exploration and
        production segment explores for, develops, produces, and markets gas and
        oil in the United States. The marketing, propane and power generation
        segment includes the sale of propane at wholesale and retail to
        customers in eight states, participation in natural gas fueled
        cogeneration projects and the marketing of natural gas and services to
        distribution companies, independent power producers and other large end
        users. 

        The following tables provide information concerning Columbia's major
        business segments. Revenues include intersegment sales to affiliated
        subsidiaries, which are eliminated when consolidated. Affiliated sales
        are recognized on the basis of prevailing market or regulated prices.
        Operating income is derived from revenues and expenses directly
        associated with each segment. Identifiable assets include only those
        attributable to the operations of each segment.


                                       66
<PAGE>   67
    ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)


<TABLE>
<CAPTION>
($ in millions)                                              1996           1995        1994
                                                            -------        -------     -------
<S>                                                         <C>            <C>         <C>
REVENUES
     Transmission and Storage          - Unaffiliated         456.2          436.0       475.9
                                       - Intersegment         354.6          324.3       282.8
                                                            -------        -------     -------
                                       TOTAL                  810.8          760.3       758.7
                                                            -------        -------     -------
                                                       
     Distribution                      - Unaffiliated       2,120.4        1,780.6     1,830.7
                                       - Intersegment           7.3            2.5           -
                                                            -------        -------     -------
                                       TOTAL                2,127.7        1,783.1     1,830.7
                                                            -------        -------     -------
                                                       
     Exploration and Production        - Unaffiliated          45.5          111.5       121.7
                                       - Intersegment          59.0           69.1        83.6
                                                            -------        -------     -------
                                       TOTAL                  104.5          180.6       205.3
                                                            -------        -------     -------
                                                       
     Marketing, Propane                - Unaffiliated         731.5          307.1       304.1
     and Power Generation              - Intersegment          84.9            6.2         1.6
                                                            -------        -------     -------
                                       TOTAL                  816.4          313.3       305.7
                                                            -------        -------     -------
                                                       
     Adjustments                       - Unaffiliated           0.4              -        14.7
     and eliminations                  - Intersegment        (505.8)        (402.1)     (368.0)
                                                            -------        -------     -------
                                       TOTAL                 (505.4)        (402.1)     (353.3)
                                                            -------        -------     -------
CONSOLIDATED                                                3,354.0        2,635.2     2,747.1
                                                            -------        -------     -------
</TABLE>


                                       67
<PAGE>   68
    ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)


<TABLE>
<CAPTION>
($ in millions)                                     1996        1995        1994
                                                   -------     -------     -------
<S>                                                <C>         <C>         <C>
OPERATING INCOME (LOSS)
      Transmission and Storage                       207.8       213.0       209.7
      Distribution                                   226.0       163.6       128.3
      Exploration and Production                      30.0         3.7        30.6
      Marketing, Propane and Power Generation         12.5        12.2        14.8
      Corporate                                        1.9        (2.3)        0.7
                                                   -------     -------     -------
      CONSOLIDATED                                   478.2       390.2       384.1
                                                   -------     -------     -------
DEPRECIATION & DEPLETION
      Transmission and Storage                       102.6       103.8       103.9
      Distribution                                    74.4        70.9        64.5
      Exploration and Production                      28.8        86.9        86.2
      Marketing, Propane and Power Generation          3.1         2.6         2.3
      Adjustments and eliminations                     6.3         5.8         4.8
                                                   -------     -------     -------
      CONSOLIDATED                                   215.2       270.0       261.7
                                                   -------     -------     -------
IDENTIFIABLE ASSETS
      Transmission and Storage                     2,761.2     2,978.9     4,150.0
      Distribution                                 2,648.3     2,295.7     2,168.9
      Exploration and Production                     421.7       412.4       746.4
      Marketing, Propane and Power Generation        289.0       125.8        97.5
      Adjustments and eliminations                  (620.2)     (360.4)     (441.3)
      Corporate and unallocated                      504.6       604.6       443.4
                                                   -------     -------     -------
      CONSOLIDATED                                 6,004.6     6,057.0     7,164.9
                                                   -------     -------     -------
CAPITAL EXPENDITURES
      Transmission and Storage                       142.7       172.5       179.1
      Distribution                                   148.4       151.8       151.4
      Exploration and Production                      12.1        86.8       101.6
      Marketing, Propane and Power Generation          6.3         6.6         4.7
      Corporate                                        5.3         4.1        10.4
                                                   -------     -------     -------
      CONSOLIDATED                                   314.8       421.8       447.2
                                                   -------     -------     -------
</TABLE>


                                       68
<PAGE>   69
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

    18. QUARTERLY FINANCIAL DATA (UNAUDITED)

        Quarterly financial data does not always reveal the trend of the
        System's business operations due to bankruptcy matters, nonrecurring
        items and seasonal weather patterns which affect earnings and related
        components of operating revenues and expenses.

<TABLE>
<CAPTION>
                                                 First       Second        Third          Fourth
($ in millions except per share data)           Quarter     Quarter       Quarter        Quarter
                                                -------      -----         -----           -----
<S>                                             <C>          <C>           <C>           <C> 
1996
Operating Revenues                              1,203.0      582.4         450.8         1,117.8
Operating Income                                  278.2       36.0          20.9           143.1
Net Income (Loss)                                 151.3        8.2(a)       (6.1)(b)        68.2(c)
Per Share Amounts
Earnings (Loss) on Common Stock                    2.99       0.15         (0.11)           1.24
                                                -------      -----         -----           -----
1995
Operating Revenues                              1,030.7      454.6         366.3           783.6
Operating Income                                  199.9       26.9          14.3           149.1
Income (Loss) before
      Extraordinary Item                          128.8       30.9          19.3          (611.3)
Extraordinary Item                                    -          -             -            71.6
Net Income (Loss)                                 128.8(d)    30.9(e)       19.3(f)       (539.7)(g)
Per Share Amounts
Earnings (Loss) before Extraordinary Item          2.55       0.61          0.38          (12.17)
Extraordinary Item                                    -          -             -            1.43
Earnings (Loss) on Common Stock                    2.55       0.61          0.38          (10.74)
                                                -------      -----         -----           -----
</TABLE>

(a) Includes a decrease in net income of $18.6 million to reflect severance and
    benefit costs associated with ongoing reengineering activities, partially
    offset by an increase in net income of $5.6 million for an adjustment to the
    loss on the sale of Columbia Development.
(b) Includes a decrease in net income of $2.5 million to reflect severance and
    benefit costs associated with ongoing reengineering activities.
(c) Includes a decrease in net income of $11.1 million to reflect severance and
    benefit costs associated with ongoing reengineering activities.
(d) Includes a decrease in net income of $5.3 million for professional fees and
    related expenses resulting from bankruptcy. Net income benefited $42.1
    million from not recording estimated interest expense on prepetition debt.
(e) Includes a decrease in net income of $6.1 million for professional fees and
    related expenses resulting from bankruptcy. Net income benefited $43.7
    million from not recording estimated interest expense on prepetition debt.
(f) Includes a decrease in net income of $6.7 million for professional fees and
    related expenses resulting from bankruptcy. Net income benefited $43.7
    million from not recording estimated interest expense on prepetition debt.
(g) Includes a decrease for the impact of emergence from bankruptcy and customer
    settlement of $649.4 million, the estimated loss on the proposed sale of
    Columbia Development of $54.8 million and an improvement of $71.6 million
    for the reapplication of SFAS No. 71.

    19. EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)

        INTRODUCTION. On April 30, 1996, Columbia sold Columbia Development, its
        wholly-owned Southwest exploration and production subsidiary, effective
        December 31, 1995. The information contained in the following tables
        includes amounts attributable to the operations and reserves of Columbia
        Development for 1995 and 1994.

        Reserve information contained in the following tables for the U.S.
        properties is management's estimate, which was reviewed by the
        independent consulting firm of Ryder Scott Company Petroleum Engineers.
        Reserves are reported as net working interest. Gross revenues are
        reported after deduction of royalty interest payments.


                                       69
<PAGE>   70
    ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)


<TABLE>
<CAPTION>

CAPITALIZED COSTS ($ in millions)                 1996            1995               1994
-------------------------------------------------------------------------------------------- 
<S>                                              <C>              <C>                <C>
CAPITALIZED COSTS AT YEAR END
     Proved properties                            475.4           486.2              1,185.8
     Unproved properties(a)                        27.4            30.1                 76.1
                                                 ------           -----              -------

Total capitalized costs                           502.8           516.3              1,261.9
Accumulated depletion                            (146.4)         (141.1)              (637.6)
                                                 ------          ------              -------

NET CAPITALIZED COSTS                             356.4           375.2                624.3
                                                 ------          ------              -------

COSTS CAPITALIZED DURING YEAR(b)
     Acquisition - Unproved properties              0.7             1.1                  7.5
      Exploration                                   2.7             4.3                 24.3
      Development                                   8.7            15.5                 69.0
                                                 ------          ------              -------
COSTS CAPITALIZED                                  12.1            20.9(c)             100.8
                                                 ------          ------              -------
</TABLE>
(a) Represents expenditures associated with properties on which evaluations have
    not been completed.
(b) Includes internal costs capitalized pursuant to the accounting policy
    described in Note 1 to Consolidated Financial Statements of $0.9 million in
    1996, $1.7 million in 1995 and $6.4 million in 1994. 
(c) Excludes capital expenditures for properties held for sale.



<TABLE>
<CAPTION>
HISTORICAL RESULTS
OF OPERATIONS                      APPALACHIA             SOUTHWEST                    TOTAL
------------------------    ----------------------   ---------------------     ------------------------

($ in millions)             1996     1995     1994   1996    1995     1994     1996     1995      1994
------------------------    ----     ----     ----   ----    ----     ----     ----     -----     -----
<S>                         <C>      <C>      <C>     <C>    <C>      <C>      <C>      <C>       <C>
Gross revenues
      Unaffiliated          43.1     46.6     56.6      -    60.1     74.3     43.1     106.7     130.9
      Affiliated            58.8     32.8     29.5      -    35.9     39.2     58.8      68.7      68.7
Production costs            21.7     21.2     23.0      -    26.7     29.0     21.7      47.9      52.0
Depletion                   28.8     39.5     37.4      -    47.0     48.4     28.8      86.5      85.8
Income tax expense          15.1      6.5      9.0      -     7.8     12.6     15.1      14.3      21.6
                            ----     ----     ----   ----    ----     ----     ----     -----     -----
RESULTS OF OPERATIONS       36.3     12.2     16.7      -    14.5     23.5     36.3      26.7      40.2
                            ----     ----     ----   ----    ----     ----     ----     -----     -----
</TABLE>
Results of operations for exploration and production activities exclude
administrative and general costs, corporate overhead and interest expense.
Income tax expense is expressed at statutory rates less Section 29 credits.

                                       70
<PAGE>   71
   ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)



<TABLE>
<CAPTION>
  OTHER EXPLORATION AND PRODUCTION DATA                              1996      1995      1994
----------------------------------------------------------------     -----     -----     -----

<S>                                                                  <C>       <C>       <C>
  AVERAGE SALES PRICE PER MCF OF GAS ($)*                             2.84      1.96      2.18
  AVERAGE SALES PRICE PER BARREL OF OIL AND OTHER LIQUIDS ($)        19.07     16.17     15.09
  PRODUCTION (LIFTING) COST PER DOLLAR OF GROSS REVENUE ($)           0.22      0.27      0.26
  DEPLETION RATE PER DOLLAR OF GROSS REVENUE ($)                      0.29      0.49      0.43
                                                                     -----     -----     -----
</TABLE>
  *INCLUDES THE EFFECT OF HEDGING ACTIVITIES 




<TABLE>
<CAPTION>
  RESERVE QUANTITY INFORMATION
-----------------------------------------------------------------------------------------------------
                                                                                            Oil and Other
                                                                                     Gas      Liquids
  Proved Reserves                                                                   (Bcf)    (000 Bbls)
  ---------------                                                                   -----    ----------

<S>                                                                                 <C>       <C> 
  Reserves as of December 31, 1993                                                  697.0     12,792
        Revisions of previous estimate                                              (31.3)     1,650
        Extensions, discoveries and other additions                                  81.7      1,386
        Production                                                                  (66.7)    (3,611)
        Purchase of reserves-in-place                                                 3.6         38
        Sale of reserves-in-place                                                    (0.5)         -
-----------------------------------------------------------------------------     -------    -------
  Reserves as of December 31, 1994                                                  683.8     12,255
        Revisions of previous estimate                                               72.4       (522)
        Extensions, discoveries and other additions                                  53.6      2,668
        Production                                                                  (65.4)    (2,849)
        Sale of reserves-in-place(a)                                               (144.9)    (9,901)
-----------------------------------------------------------------------------     -------    -------
  Reserves as of December 31, 1995                                                  599.5      1,651
        Revisions of previous estimate                                               78.9       (169)
        Extensions, discoveries and other additions                                   5.5        161
        Production                                                                  (33.6)      (281)
        Sale of reserves-in-place                                                    (5.8)      (588)
-----------------------------------------------------------------------------     -------    -------
  RESERVES AS OF DECEMBER 31, 1996                                                  644.5        774
-----------------------------------------------------------------------------     -------    -------
  Proved developed reserves as of December 31,
        1994                                                                        543.3     11,504
        1995                                                                        471.6      1,608
        1996                                                                        518.3        730
-----------------------------------------------------------------------------     -------     ------
</TABLE>
  (a) Includes the sale of Columbia Development 

                                       71
<PAGE>   72
    ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

<TABLE>
<CAPTION>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
---------------------------------------------------------------------------------------------------------------------



                                    APPALACHIA                     SOUTHWEST                        TOTAL
-------------------------------------------------------  ----------------------------  ------------------------------

($ in millions)              1996      1995      1994      1996      1995      1994      1996      1995     1994
--------------------------------------------------------------------------------------------------------------------

<S>                          <C>       <C>       <C>       <C>       <C>       <C>       <C>       <C>       <C>
Future cash inflows          2,389.1   1,793.8   1,274.8      -         -       392.5    2,389.1   1,793.8   1,667.3
Future production costs       (715.5)   (606.7)   (380.9)     -         -      (111.1)    (715.5)   (606.7)   (492.0)
Future development costs      (165.8)   (166.3)   (124.5)     -         -       (43.5)    (165.8)   (166.3)   (168.0)
Future income tax expense     (499.7)   (327.1)   (233.8)     -         -       (46.8)    (499.7)   (327.1)   (280.6)
--------------------------------------------------------------------------------------------------------------------

Future net cash flows        1,008.1     693.7     535.6      -         -       191.1    1,008.1     693.7     726.7
Less 10% discount              574.4     377.7     285.4      -         -        35.0      574.4     377.7     320.4
--------------------------------------------------------------------------------------------------------------------

STANDARDIZED MEASURE OF
  DISCOUNTED FUTURE
  NET CASH FLOW                433.7     316.0     250.2      -         -       156.1      433.7     316.0     406.3
--------------------------------------------------------------------------------------------------------------------
</TABLE>


    Future cash inflows are computed by applying year-end prices to estimated
    future production of proved gas and oil reserves. Future expenditures (based
    on year-end costs) represent those costs to be incurred in developing and
    producing the reserves. Discounted future net cash flows are derived by
    applying a 10 percent discount rate, as required by the Financial Accounting
    Standards Board, to the future net cash flows. This data is not intended to
    reflect the actual economic value of Columbia's gas and oil producing
    properties or the true present value of estimated future cash flows since
    many arbitrary assumptions are used. The data does provide a means of
    comparison among companies through the use of standardized measurement
    techniques.



                                       72

<PAGE>   73


   ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

        A reconciliation of the components resulting in changes in the
        standardized measure of discounted cash flows attributable to proved gas
        and oil reserves for the three years ending December 31 follows:
<TABLE>
<CAPTION>

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

($ in millions)                           1996            1995            1994
                                         ------          ------          ------

<S>                                       <C>             <C>             <C>  
Beginning of year                         316.0           406.3           551.4
                                         ------          ------          ------

Gas and oil sales,
   net of production
   costs                                  (80.2)         (124.3)         (147.6)

Net changes in prices
   and production costs                   170.4           132.7          (236.5)

Change in future
   development costs                        0.5           (49.7)            4.1

Extensions, discoveries
   and other additions,
   net of related costs                     9.4           106.5            68.2

Revisions of previous
   estimates, net of
   related costs                           90.1            72.5           (17.3)

Sales of reserves-in-place                (18.4)         (195.6)           (0.5)

Purchases of reserves-in-place              -               -               1.0

Accretion of discount                      46.0            55.2            77.8

Net change in income taxes                (65.3)          (64.9)           80.8

Timing of production
   and other changes                      (34.8)          (22.7)           24.9
                                          -----          ------           -----

            END OF YEAR                   433.7           316.0           406.3
                                          -----          ------           -----
</TABLE>


    The estimated discounted future net cash flows increased during 1996
    primarily due to net changes in prices and production costs, extensions,
    discoveries and other additions, as well as revisions to the economic
    feasibility of producing certain wells.

                                       73
<PAGE>   74
    ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)

                                                                     Schedule II
                        VALUATION AND QUALIFYING ACCOUNTS
                 The Columbia Gas System, Inc. and Subsidiaries
                             Year Ended December 31,
                                 ($ in Millions)


<TABLE>
<CAPTION>
                                                            Additions - Charged to
                                                            ----------------------
                                              Beginning                    Other        Deductions     Ending
  Description                                 Balance       Income     Accounts (a)         (b)        Balance
  -----------                                 ---------     ------     ------------     ----------     -------

  Reserves deducted in the balance sheet
    from the assets to which they apply:

          Allowance for doubtful accounts

<S>                                              <C>        <C>           <C>              <C>           <C>
             1996                                12.3       25.6          17.7             39.4          16.2

             1995                                11.6       31.6          11.3             42.2          12.3

             1994                                11.8       21.5          15.8             37.5          11.6
</TABLE>





    (a) Reflects reclassification to a regulatory asset of the uncollectible
        accounts related to the Percent of Income Plan (PIP) of Columbia Gas of
        Ohio, Inc.
    (b) Principally reflects amounts charged off as uncollectible less amounts
        recovered.

                                       74

<PAGE>   75



   ITEM 9.

   CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
   DISCLOSURE There has not been a change of accountants nor any disagreements
   concerning accounting and financial disclosure within the past two years.


                                    PART III

   ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
   Certain information required by this item is contained in Columbia's Proxy
   Statement related to the 1996 Annual Meeting of Stockholders, to be filed
   pursuant to Section 14 of the Securities Exchange Act of 1934 and is
   incorporated herein by reference.

   Information regarding Columbia's current executive officers, is as follows:

   OLIVER G. RICHARD III, 44, Chairman, Chief Executive Officer and President of
   The Columbia Gas System, Inc. (effective April 28, 1995). Chairman of New
   Jersey Resources Corporation from 1992 to 1995; President and Chief Executive
   Officer from 1991 to 1995. President and Chief Executive Officer of Northern
   Natural Gas Company from 1989 to 1991. Senior Vice President of Enron Gas
   Pipeline Group from 1987 to 1989. Vice President and subsequently Executive
   Vice President of Enron Gas Pipeline Group from 1987 to 1989. Vice President
   and General Counsel of Tenngasco, a subsidiary of Tenneco Corporation, from
   1985 to 1987. Federal Energy Regulatory Commission Commissioner from 1982 to
   1985.

   PETER M. SCHWOLSKY, 50, Senior Vice President and Chief Legal Officer of
   Columbia and Columbia Gas System Service Corporation since August 1995.
   Senior Vice President of Columbia and the Columbia Gas System Service
   Corporation from June 1995 to August 1995. Executive Vice President, Law and
   Corporate Development, for New Jersey Resources Corporation from 1991 to
   1995. Of counsel and then Partner with Steptoe & Johnson from 1986 to 1991.

   MICHAEL W. O'DONNELL, 52, Senior Vice President and Chief Financial Officer
   of Columbia since October 1993. Senior Vice President and Assistant Chief
   Financial Officer of the Columbia Gas System Service Corporation since 1989.

   CATHERINE GOOD ABBOTT, 46, Chief Executive Officer of Columbia Transmission
   and Columbia Gulf Transmission Company since January 1996. Principal with Gem
   Energy Consulting, Inc. from 1995 to January 1996. Vice president for various
   business units of Enron Corporation from 1985 to 1995.

   STEPHEN J. HARVEY, 36, Vice President of Columbia since January 1996.
   Principal with Gem Energy Consulting, Inc., from 1995 to January 1996.
   President of NJR Energy, a subsidiary of New Jersey Resources, from 1993 to
   1995.

   Information regarding Columbia's former executive officers is as follows:

   C. RONALD TILLEY, 61, former Chairman and Chief Executive Officer of Columbia
   Distribution Companies from January 1987 to January 1996.

   JAMES P. HOLLAND, 48, former Chairman and Chief Executive Officer of Columbia
   Transmission and Columbia Gulf from September 1990 to January 1996.



                                       75

<PAGE>   76

   ITEM 11. EXECUTIVE COMPENSATION

   Information required by this item is contained in Columbia's Proxy Statement
   related to the 1997 Annual Meeting of Stockholders, to be filed pursuant to
   Section 14 of the Securities Exchange Act of 1934 and is incorporated herein
   by reference.

   ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

   Information required by this item is contained in Columbia's Proxy Statement
   related to the 1997 Annual Meeting of Stockholders, to be filed pursuant to
   Section 14 of the Securities Exchange Act of 1934 and is incorporated herein
   by reference.

   ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

   Information required by this item is contained in Columbia's Proxy Statement
   related to the 1997 Annual Meeting of Stockholders, to be filed pursuant to
   Section 14 of the Securities Exchange Act of 1934 and is incorporated herein
   by reference.

                                     PART IV

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

   Exhibits
   Reference is made to pages 78 through 80 for the list of exhibits filed as a
   part of this Annual Report on Form 10-K.

   Pursuant to Item 601(b), paragraph (4)(iii)(A) of Regulation S-K, certain
   instruments representing long-term debt of Columbia or its subsidiaries have
   not been included as Exhibits because such debt does not exceed 10% of the
   total assets of Columbia and its subsidiaries on a consolidated basis.
   Columbia agrees to furnish a copy of any such instrument to the SEC upon
   request.

   Financial Statement Schedules
   All of the financial statements and financial statement schedules filed as a
   part of the Annual Report on Form 10-K are included in Item 8.

   Reports on Form 8-K
   A report on Form 8-K was filed on January 28, 1997, containing a Press
   Release published on January 27, 1997, regarding the financial and operating
   results for the year ended December 31, 1996.

   Undertaking made in Connection with 1933 Act Compliance on Form S-8
   For purposes of complying with the amendments to the rules governing Form S-8
   under the Securities Act of 1933, Columbia undertakes the following, which is
   incorporated by reference into the registration statements on Form S-8, Nos.
   33-03869 (filed May 16, 1996) and 33-42776 (filed September 13, 1991):

   Insofar as indemnification for liabilities arising under the Securities Act
   of 1933 (Act) may be permitted to directors, officers and controlling persons
   of the registrant pursuant to the foregoing provisions, or otherwise, the
   registrant has been advised that in the opinion of the Securities and
   Exchange Commission such indemnification is against public policy as
   expressed in the Act and is, therefore, unenforceable. In the event that a
   claim for indemnification against such liabilities (other than the payment by
   the registrant of expenses incurred or paid by a director, officer or
   controlling person of the registrant in the successful defense of any action,
   suit or proceeding) is asserted by such director, officer or controlling
   person in connection with the securities being registered, the registrant
   will, unless in the opinion of its counsel the matter has been settled by
   controlling precedent, submit to a court of appropriate jurisdiction the
   questions whether such indemnification by it is against public policy as
   expressed in the Act and will be governed by the final adjudication of such
   issue.

                                       76

<PAGE>   77

                                   SIGNATURES

   Pursuant to the requirements of Section 13 or 15(d) of the Securities
   Exchange Act of 1934, the registrant has duly caused this report to be signed
   on its behalf by the undersigned, thereunto duly authorized.

                                            THE COLUMBIA GAS SYSTEM, INC.
                                                 (Registrant)
  Dated:         March 14, 1997
                                            By: /s/ Oliver G. Richard III
                                               -------------------------------
                                                   (Oliver G. Richard III)
                                                      Director (Principal
                                                      Executive Officer)

   Pursuant to the requirements of the Securities Exchange Act of 1934, this
   report has been signed below by the following persons on behalf of the
   registrant and in the capacities and on the dates indicated.


<TABLE>
<S>               <C>                               <C>               <C>
Mar. 14, 1997     /s/Oliver G. Richard III          Mar. 14, 1997     /s/Jeffrey W. Grossman
                  -----------------------------                       -----------------------
                  Director (Principal                                 Vice President & Controller
                  Executive Officer)                                  (Principal Accounting Officer)

Mar. 14, 1997     /s/Richard F. Albosta             Mar. 14, 1997     /s/Robert H. Beeby
                  -----------------------------                       -----------------------
                  Richard F. Albosta                                  Robert H. Beeby
                  Director                                            Director

Mar. 14, 1997     /s/Wilson K. Cadman               Mar. 14, 1997     /s/Malcolm T. Hopkins
                  -----------------------------                       -----------------------
                  Wilson K. Cadman                                    Malcolm T. Hopkins
                  Director                                            Director

Mar. 14, 1997                                       Mar. 14, 1997     /s/William E. Lavery
                  -----------------------------                       -----------------------
                  James Heffernan                                     William E. Lavery
                  Director                                            Director

Mar. 14, 1997     /s/Donald P. Hodel                Mar. 14, 1997     /s/Michael W. O'Donnell
                  -----------------------------                       -----------------------
                  Donald P. Hodel                                     Michael W. O'Donnell
                  Director                                            Senior Vice President
                                                                      (Chief Financial Officer)

Mar. 14, 1997     /s/Malcolm Jozoff                 Mar. 14, 1997     /s/Douglas E. Olesen
                  -----------------------------                       -----------------------
                  Malcolm Jozoff                                      Douglas E. Olesen
                  Director                                            Director

Mar. 14, 1997     /s/Gerald E. Mayo                 Mar. 14, 1997     /s/James R. Thomas, II
                  -----------------------------                       -----------------------
                  Gerald E. Mayo                                      James R. Thomas, II
                  Director                                            Director

Mar. 14, 1997     /s/Ernesta G. Procope             Mar. 14, 1997     /s/William R. Wilson
                  -----------------------------                       -----------------------
                  Ernesta G. Procope                                  William R. Wilson
                  Director                                            Director

Mar. 14, 1997
                  -----------------------------
                  J. Bennett Johnston
                  Director
</TABLE>



                                       77

<PAGE>   78



                                  EXHIBIT INDEX

                 Reference is made in the two right-hand columns below to those
  exhibits which have heretofore been filed with the U.S. Securities and
  Exchange Commission. Exhibits so referred to are incorporated herein by
  reference.

<TABLE>
<CAPTION>
                                                                                      Reference
                                                                                ---------------------
                                                                                File No.      Exhibit
                                                                                ---------     -------
<S>                                                                             <C>            <C>
  3-A       -   Restated Certificate of Incorporation of The Columbia           1-1098         3-A
                Gas System, Inc., dated as of November 28, 1995.
  3-B       -   By-Laws of The Columbia Gas System, Inc., as amended dated      1-1098         3-B
                November 18, 1987.
  4-A       -   Indenture between The Columbia Gas System, Inc.                 33-64555       4-S
                and Marine Midland Bank, N.A. Trustee, dated as of
                November 28, 1995.
  4-B       -   First Supplemental Indenture, between The Columbia Gas          33-64555       4-T
                System, Inc. and Marine Midland Bank, N.A. Trustee,
                dated as of November 28, 1995.
  4-C       -   Second Supplemental Indenture, between The Columbia Gas         33-64555       4-U
                System, Inc., and Marine Midland Bank, N.A. Trustee,
                dated as of November 28, 1995.
  4-D       -   Third Supplemental Indenture, between The Columbia Gas          33-64555       4-V
                System, Inc. and Marine Midland Bank, N.A. Trustee,
                dated as of November 28, 1995.
  4-E       -   Fourth Supplemental Indenture, between The Columbia Gas         33-64555       4-W
                System, Inc. and Marine Midland Bank, N.A. Trustee,
                dated as of November 28, 1995.
  4-F       -   Fifth Supplemental Indenture, between The Columbia Gas          33-64555       4-X
                System, Inc. and Marine Midland Bank, N.A. Trustee,
                dated as of November 28, 1995.
  4-G       -   Sixth Supplemental Indenture, between The Columbia Gas          33-64555       4-Y
                System, Inc. and Marine Midland Bank, N.A. Trustee, dated
                as of November 28, 1995.
  4-H       -   Seventh Supplemental Indenture, between The Columbia            33-64555       4-Z
                Gas System, Inc. and Marine Midland Bank, N.A., Trustee,
                dated as of November 28, 1995.
  10-P(a)   -   Pension Restoration Plan of The Columbia Gas                    1-1098         10-P
                System, Inc., amended October 9, 1991.
  10-Q(a)   -   Thrift Restoration Plan of The Columbia Gas                     1-1098         10-Q
                System, Inc. dated January 1, 1989.
  10-T      -   Agreement and Bridge Agreement dated                            1-1098         10-T
                December 1, 1993, between Columbia Gas
                Transmission Corporation and Consol
                Pennsylvania Coal Company.
  10-AE     -   U.S. Environmental Protection Agency Administrative             1-1098         10-AE
                Order by Consent for Removal Actions for Columbia Gas
                Transmission Corporation dated September 22,1994.
  10-AF     -   Amended and Restated Indenture of Mortgage and                  1-1098         10-AF
                Deed of Trust by Columbia Gas Transmission
                Corporation to Wilmington Trust Company,
                dated as of November 28, 1995
</TABLE>

----------
(a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K.


                                       78

<PAGE>   79


  ITEM 14.       EXHIBIT INDEX (Continued)


<TABLE>
<CAPTION>
                                                                                          Reference
                                                                                     ---------------------
                                                                                     File No.      Exhibit
                                                                                     ---------------------
<S>                                                                                  <C>             <C>  
  10-BB(a)  -   Annual Incentive Compensation Plan of The Columbia Gas               1-1098          10-BB
                System, Inc., dated November 16, 1988.
  10-BC(a)  -   Employment Agreement between Oliver G. Richard III                   1-1098          10-BC
                and The Columbia Gas System, Inc., dated March 15, 1995.
  10-BE(a)  -   Employment Agreement between Peter M. Schwolsky                      1-1098          10-BE
                and The Columbia Gas System, Inc., dated May 30, 1995.
  10-BF(a)  -   Employment Agreement between Catherine Good Abbott
                and The Columbia Gas System, Inc., dated January 17, 1996.
  10-BU     -   Share Sale and Purchase Agreement between The                        1-1098          10-BU
                Columbia Gas System, Inc. and Anderson Exploration
                Ltd. dated November 25, 1991.
  10-BV     -   Security Agreement dated as of January 15, 1992,                     1-1098          10-BV
                between The Columbia Gas System, Inc. and
                Anderson Exploration Ltd. and Montreal Trust
                Company of Canada.
  10-BW     -   Kotaneelee Litigation Indemnity Agreement dated                      1-1098          10-BW
                as of December 31, 1991, among The Columbia
                Gas System, Inc. and Columbia Gas Development
                of Canada Ltd. and Anderson Exploration Ltd.
  10-BX     -   Specified Litigation Indemnity Agreement made                        1-1098          10-BX
                as of December 31, 1991, among The Columbia
                Gas System, Inc. and Columbia Gas Development
                of Canada Ltd. and Anderson Exploration Ltd.
  10-BY(a)  -   Columbia Gas Restoration Security Trust                              1-1098          10-BY
                Agreement dated June 1, 1991 with Dauphin
                Deposit Bank and Trust Company.
  10-CA(a)  -   The Columbia Gas System, Inc. Retirement Plan                        1-1098          10-CA
                for Outside Directors, as amended, August 21, 1991.
  10-CB     -   Credit Agreement, dated as of                                        1-1098          10-CB
                November 28, 1995, among The Columbia Gas System,
                Inc., certain banks party thereto and Citibank, N.A.
  10-CC     -   First Amendment and Supplement to Credit                             1-1098          10-CC
                Agreement, dated December 6, 1995
  10-CJ     -   Amended and Restated Agreement of Cove Point                         1-1098          10-CJ
                LNG Limited Partnership between Columbia LNG and
                PEPCO Energy Company, Inc. dated January 27, 1994.
  10-CM     -   Plan of Reorganization for Columbia Gas Transmission Corporation     1-1098          10-CM
                as filed with the United States Bankruptcy Court for the District
                of Delaware on January 18, 1994.
  11*       -   Statements Re: Computation of Per Share Earnings.
  12*       -   Statements of Ratio of Earnings to Fixed Charges
                and Preferred Stock Dividends.
  21*       -   Subsidiaries of The Columbia Gas System, Inc.
  23-A*     -   Letter report, dated January 21, 1997, and the written
                consent to the filing and use of information contained in
                such letter report, Reports and Registration Statements
                filed during 1997, of Ryder Scott Company Petroleum
                Engineers, independent petroleum and natural gas
                consultants.
</TABLE>
----------
(a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K.
 *  Filed herewith.

                                       79

<PAGE>   80


  ITEM 14.       EXHIBIT INDEX (Continued)


<TABLE>
<CAPTION>
                                                                                      Reference
                                                                                ---------------------
                                                                                File No.      Exhibit
                                                                                --------      -------

<S>                                                                             <C>           <C>
  23-B*     -   Written consent of Arthur Andersen LLP,
                independent public accountants, to the
                incorporation by reference of their report
                included in the 1996 Annual Report on Form
                10-K of The Columbia Gas System, Inc. and
                their report included in The Columbia Gas
                System, Inc.'s 1996 Annual Report to Shareholders
                in the registration statements on Form S-8
                (File No. 33-03869), and Form S-8
                (File No. 33-42776).
  27*       -   Financial Data Schedule for the period ended
                December 31, 1996.
</TABLE>




----------
  *Filed herewith.




                                       80