<PAGE>   1

This amendment contains a corrected 1997 Form 10K in its entirety. The original
filing included typographical errors that occurred during the EDGARization
process. The corrections for these errors are as follows:
        Item 6. page 13 - 1997 Total operating revenues should be $5,053.6
                million
        Item 6. page 13 - 1995 Earnings (Loss) per common share before
                extraordinary item and accounting change should be $(8.57)
        Item 7. page 20 - Low and close market price for the quarter ended 
                March 31, 1997, should be $57 5/8 and $57 7/8, respectively
        Item 8. page 41 - 1997 Other taxes should be $222.5 million
        Item 8. page 42 - 1997 Regulatory Assets should be $400.9 million
<PAGE>   2
                                                      Commission File No. 1-1098

      As filed with the United States Securities and Exchange Commission on
                                 March 19, 1998.



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

                                   
                                 FORM 10-K/A
                               AMENDMENT NO. 1

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

                   For the Fiscal Year Ended DECEMBER 31, 1997

                                       or

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

                  For the Transition Period from ______to ______

                              COLUMBIA ENERGY GROUP
             (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:

<TABLE>
<CAPTION>

                                                          Name of Each Exchange
Title of Each Class                                        on Which Registered
-------------------                                        -------------------
<S>                                                      <C>
Common Stock, $10 Par Value . . . . . . . . . . . .      New York Stock Exchange
</TABLE>

<TABLE>
<CAPTION>

Debentures
<S>   <C>
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
</TABLE>

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

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the 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. [X]

The aggregate market value of the outstanding common shares of the Registrant
held by nonaffiliates as of January 31, 1998, was $4,195,400,000. 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,
1998, was: Common Stock $10 Par Value: 55,507,078 shares outstanding.

                       Documents Incorporated by Reference
                       -----------------------------------
Part III of this report incorporates by reference the Registrant's Proxy
Statement relating to the 1998 Annual Meeting of Stockholders.

<PAGE>   3

                                    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................................     39

     Item 9.  Change In and Disagreements with Accountants on Accounting and
              Financial Disclosure.......................................................     70

Part III

     Item 10. Directors and Executive Officers of the Registrant.........................     70

     Item 11. Executive Compensation.....................................................     70

     Item 12. Security Ownership of Certain Beneficial Owners and Management.............     70

     Item 13. Certain Relationships and Related Transactions.............................     71

Part IV

     Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............     71

     Undertaking made in Connection with 1933 Act Compliance on Form S-8.................     71

     Signatures..........................................................................     72
</TABLE>

<PAGE>   4

                                     PART 1

ITEM 1. BUSINESS

General

Columbia Energy Group (Columbia), formerly The Columbia Gas System, Inc. 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 and electricity, 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 17 direct
subsidiaries. Columbia owns all of the securities of these direct 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 Columbia Group.

On January 20, 1998, Columbia announced that its name had been changed from The
Columbia Gas System, Inc. to Columbia Energy Group to better reflect its
expanded participation in the energy marketplace.

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 18,500-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 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 in Cove Point, Maryland. The facility has the capacity to liquefy
natural gas at a rate of 15,000 Mcf of natural gas per day. The facility enables
liquefied natural gas to be stored until needed for the winter peak-day
requirements of utilities and other large gas users.

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. Approximately 31,700 miles
of distribution pipelines serve these major markets. The distribution
subsidiaries have initiated transportation programs that allow residential and
small commercial customers the opportunity to choose their natural gas suppliers
and to use the distribution subsidiaries for transportation service. This
ability to choose a supplier was previously limited to larger commercial and
industrial customers. See "Competition and Business Strategies" on page 4 for
additional information.


Exploration and Production Operations

Columbia's exploration and production subsidiary, Columbia Natural Resources,
Inc. (Columbia Resources), explores for, develops, gathers and produces natural
gas and oil in Appalachia and Canada. As of December 31, 1997, Columbia
Resources held interest in approximately 2.1 million net acres of gas and oil
leases and had proved gas reserves of nearly 811 billion cubic feet of natural
gas equivalent. On August 7, 1997, Columbia Resources acquired Alamco, Inc.
(Alamco), an Appalachian gas and oil exploration and development company and
during the 


                                       3
<PAGE>   5

ITEM 1. BUSINESS (Continued)

first quarter of 1998, Columbia Resources purchased 26 producing wells and
approximately 5,000 undeveloped acres in Ontario, Canada. For additional
information, see Item 7, page 32.

Marketing, Propane and Power Generation Operations

Columbia Energy Services Corporation (Columbia Energy Services), and its
subsidiaries conduct Columbia's nonregulated natural gas and power marketing
operations and provide an array of energy 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 Services is also actively pursuing opportunities to provide
natural gas supplies to retail customers as a result of the unbundling of
services that is occurring at the local distribution level. Columbia Energy
Services, through its subsidiary, Columbia Service Partners, Inc. (Columbia
Service), provides a variety of nonregulated services to both homeowners and
businesses. In the second quarter of 1997, Columbia Energy Services acquired
PennUnion Energy Services L.L.C. (PennUnion), an energy-marketing affiliate of
the Pennzoil Company. As a result of this acquisition, Columbia Energy Services
markets a substantial portion of Pennzoil Company's North American natural gas
production. During 1997, Columbia Energy Services began purchasing and marketing
Kerr-McGee Corporation's (Kerr-McGee) offshore natural gas production. Columbia
Energy Services will manage all of Kerr-McGee's U.S. natural gas marketing
activities including scheduling, nominating and balancing pipeline
transportation as well as providing financial risk management services. In
October 1997, Columbia Energy Services and Honeywell Inc. formed an alliance to
sell a targeted set of products and services in a seven-state region for use in
homes, commercial buildings and industrial facilities. See Item 7, page 35, for
additional information.

During 1997, Commonwealth Propane, Inc. merged into Columbia Propane Corporation
(Columbia Propane), both wholly-owned subsidiaries of Columbia, in order to
increase administrative and operating efficiencies. Columbia Propane sells
propane at wholesale and retail to nearly 97,000 customers in parts of ten
states and the District of Columbia. During the first quarter of 1997, the
assets of Supertane Gas Corporation were purchased, bringing total propane sales
for 1997 to 70.9 million gallons. In the first quarter of 1998, Columbia Propane
purchased certain assets of Central Jersey Propane, Inc. (Ace Gas) located in
New Jersey. Ace Gas sells approximately 2.2 million gallons of propane annually
to 3,600 customers. For additional information, see Item 7, page 36.

Columbia Electric Corporation (Columbia Electric), formally TriStar Ventures
Corp., a wholly owned subsidiary of Columbia, holds interests in three
cogeneration projects that produce both electricity and useful thermal energy.
These projects are fueled principally by natural gas and have a total capacity
of nearly 250 megawatts. In the first quarter of 1998, Columbia Electric entered
into a joint ownership agreement to develop three natural gas-fired electricity
generating plants by 2001. In total, the three plants will provide approximately
1000 megawatts of electricity using approximately 160 Mmcf per day of natural
gas. Total development costs are estimated at $600 million to $700 million.

Columbia Network Services Corporation (Columbia Network), a wholly owned
subsidiary of Columbia, and through its subsidiaries provides telecommunications
and information services and assists personal communications services and other
microwave radio service licensees in locating and constructing antenna
facilities. In October 1996, Columbia Network entered into an agreement with The
SABRE Group, Inc. (SABRE) to jointly develop an electronic information system
which will operate under the name of The SABRE Energy Network. The SABRE Energy
Network will serve as a central access point for scheduling natural gas
transportation.

For additional discussion of the Columbia Group's business segments, including
financial information for the last three fiscal years, see Item 7, pages 21
through 38 and Note 16 on pages 62 through 64 of Item 8.

Competition and Business Strategies

The energy markets continue to undergo 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 service 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 programs that provide residential
customers the opportunity to purchase their natural gas requirements from third
parties and use the distribution subsidiaries for transportation services. It is
likely, that over time, distribution companies will have a very limited merchant
function. At the same time that the natural gas markets 


                                       4
<PAGE>   6

ITEM 1. BUSINESS (Continued)

are evolving, the markets for competing energy sources are also changing. During
1997, open access to interstate transmission of electricity was approved by the
Federal Energy Regulatory Commission (FERC) and will 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 that 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-related services. To achieve this goal, Columbia
has developed the following strategic initiatives:

         Develop Nonregulated Energy Business. Columbia has established a
strategic goal to increase its investment in non-rate regulated businesses to a
level that would provide for such operations to contribute approximately 30% of
Columbia's consolidated operating income by 2002. 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 non-rate
regulated energy-related products and services. Through Columbia Energy
Services, 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. Columbia's Appalachian exploration and
production subsidiary, Columbia Resources, acquired Alamco, Inc. in the third
quarter of 1997, making it one of the largest-volume natural gas and oil
producers in the Appalachian Basin. This acquisition provides contiguous assets
that give Columbia Resources a major presence in north-central West Virginia,
southern Kentucky and northern Tennessee. In late 1997, Columbia Resources
entered into an agreement to purchase producing assets and undeveloped acreage
in Ontario, Canada with consummation of the transaction expected in the first
half of 1998.

         Capitalize on Core Asset Strengths. Columbia continues to focus on and
expand its core businesses. Consistent with this focus, Columbia has undertaken
an expansion of Columbia Transmission's storage and transportation systems that
are being phased in over a three-year period that began in 1997. Once completed,
the expansion will add approximately 500,000 Mcf per day of firm storage to 23
customers. Columbia Transmission is also participating in the proposed 442-mile
Millennium Pipeline Project that has been submitted to the FERC for approval. As
proposed, the project will transport approximately 700,000 Mcf per day of
natural gas from the Lake Erie region to eastern markets. For additional
information regarding the Millennium project see Item 7, page 21.

         Exploit Synergies. Unlike the structure of many of its peers,
Columbia's distribution, storage, and exploration and production operations form
a grid connected 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 working on initiatives
with regulators designed to promote rate structures that will reward Columbia's
transmission and distribution subsidiaries for enhanced productivity and
efficiency.

         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. These studies resulted in
recommendations that were being implemented during 1997. The benefits of this
reengineering initiative are now being 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. 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 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 1997, had reduced its ratio of long-term debt to total capitalization
to 53%. In 1997, Fitch Investors Service (Fitch), Moody's Investors Service,
Inc. (Moody's) and Standard & Poor's Ratings Group (S&P) upgraded Columbia's
long-term debt rating to BBB+, Baa1 and BBB+, respectively. 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 


                                       5
<PAGE>   7

ITEM 1. BUSINESS (Continued)

opportunities as they arise. To further enhance its financial flexibility,
Columbia recently implemented unsecured revolving credit facilities totaling
$1.35 billion, consisting of a $900 million five-year revolving credit facility
and a $450 million 364-day revolving credit facility with a one-year term loan
option. The $900 million five-year facility will provide for the issuance of up
to $300 million of letters of credit. The credit facilities also support
Columbia's commercial paper program.

The foregoing discussion includes statements regarding market risk sensitive
instruments and 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. Investors and prospective investors 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 statements concerning Columbia's plans, objectives, expected
performance, expenditures and recovery of expenditures through rates, stated on
either a consolidated or segment basis, and including any and all underlying
assumptions and other statements that are other than statements of historical
fact. From time to time, Columbia may publish or otherwise make available
forward-looking statements of this nature. All such subsequent forward-looking
statements, whether written or oral and whether made by or on behalf of
Columbia, are also expressly qualified by these cautionary statements. All
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 and commodity market conditions many
of which are beyond the control of Columbia. In addition, the relative
contributions to profitability by segment, and the assumptions underlying the
forward-looking statements relating thereto, may change over time due to changes
in the marketplace.

With respect to any references made to ratings assigned to Columbia's debt
securities, there can be no assurance that Columbia will be successful at
maintaining its credit quality 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.

Other Relevant Business Information

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

As of January 31, 1998, the Columbia Group had 8,529 full-time employees of
which 2,443 are subject to collective bargaining agreements.

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. Information relating to environmental
matters is detailed in Item 7, pages 22 and 28, and in Item 8, Note 13 on page
60.

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


                                       6
<PAGE>   8


ITEM 2.  PROPERTIES


Information relating to properties of subsidiary companies is detailed below and
on page 8 and page 47 of Item 8 under Note 1F. Assets under lien and other
guarantees are described on page 60 in Note 13C 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 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, 1997

<TABLE>
<CAPTION>
                            Developed Acreage              Undeveloped Acreage
                            -----------------            ----------------------    
                            Gross         Net            Gross              Net
                            -----         ---            -----              ---                         
<S>                       <C>            <C>            <C>            <C>    
Appalachian ........      1,447,656      1,406,597        813,519        664,139
                          =========      =========      =========      =========
</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>
1997......        0           0           84         18          84           18
1996......        0           0           19          8          19(a)         8
1995......        4           4           64         21          68(a)        25
</TABLE>

Productive and Drilling Wells - At December 31, 1997


<TABLE>
<CAPTION>
              Production Wells
    --------------------------------------
    Gross(b)                      Net                    Wells Drilling
 -------------              --------------          ----------------------
 Gas       Oil              Gas        Oil          Gross              Net
 ---       ---              ---        ---          -----              ---
<S>        <C>              <C>        <C>          <C>                <C>
7,343      138              6,728      84             27                17
</TABLE>

(a)  Includes 1 net horizontal well in 1996 and 18 net horizontal wells in 1995.
(b)  Includes 778 multiple completion gas wells, all of which are included as
     single wells in the table. Also includes 1 gross productive horizontal
     well.


                                       7
<PAGE>   9
ITEM 2. PROPERTIES (continued)

            GAS PROPERTIES OF SUBSIDIARIES - AS OF DECEMBER 31, 1997
<TABLE>
<CAPTION>
                                              Underground Storage                Miles of Pipeline               Compressor Stations
                                              --------------------  ------------------------------------------  --------------------
                                                                      Gathering                                          Installed
Subsidiaries                            State     Acreage    Wells    and Storage   Transmission  Distribution  Number  Capacity(hp)
-------------------------------------   -----    --------  -------   -------------  -------------- ------------ ------- ------------
<S>                                     <C>      <C>       <C>       <C>            <C>            <C>           <C>      <C>
Columbia Gas of Kentucky, Inc.          KY             --        --             --              --        2,374      --           --
Columbia Gas of Maryland, Inc.          MD             --        --             --              --          595      --           --
Columbia Gas of Ohio, Inc.              OH             --        --             --              --       17,914      --           --
Columbia Gas of Pennsylvania, Inc.      PA          3,400         8              4              --        6,908       1          800
Columbia Gas of Virginia, Inc.          VA             --        --             --              --        3,873      --           --
Columbia Gas Transmission Corporation   DE             --        --             --               3           --      --           --
                                        KY             --        --             32             745           --       7       18,270
                                        MD            945        --             22             227           --       1       12,000
                                        NJ             --        --             --              69           --      --           --
                                        NY         26,084       143             58             487           --       4        6,040
                                        NC             --        --             --               1           --       1        1,200
                                        OH        486,892     2,467            992           4,029           --      27      100,312
                                        PA         63,351       245            578           2,062           --      27       68,913
                                        VA             --        --            130           1,123           --      11       79,480
                                        WV        293,711       817          1,236           2,507           --      46      304,736
Columbia Gulf Transmission Company      AR             --        --             --               8           --      --           --
                                        KY             --        --             --             716           --       2       70,290
                                        LA             --        --             --           2,041           --       5      192,500
                                        MS             --        --             --             659           --       3      121,382
                                        TN             --        --             --             556           --       2       83,000
                                        TX             --        --             --             200           --      --           --
                                        WY             --        --             --              10           --      --           --
Columbia Natural Resources, Inc.        KY             --        --          1,872              --           --       8          125
                                        MI             --        --              6              --           --      --           --
                                        NY             --        --              2              --           --      --           --
                                        OH             --        --            112              --           --      --           --
                                        PA             --        --             37              --           --      --           --
                                        VA             --        --            393              --           --      --           --
                                        WV             --        --          2,529              --           --      --           --
                                                ----------  -------  --------------  --------------  -------------  ----  ----------
                                                   874,383    3,680          8,003          15,443       31,664     145    1,059,048
                                                ==========  =======  ==============  ==============  =============  ====  ==========
</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 know 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 Transmissions's property has
      been, pledged to Columbia as security for First Mortgage Bonds issued by
      Columbia Transmission to Columbia.



                                       8
<PAGE>   10

ITEM 3. LEGAL PROCEEDINGS

I.  Purchase and Production Matters

         A.  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 Item 7, 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' 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.

                  Consistent with the order of the Texas Supreme Court of
October 18, 1996, a new trial was held regarding New Ulm's fraud claim and on
July 31, 1997, the jury returned a verdict that awarded plaintiff $512,070
compensatory damages and $2,560,350 punitive damages.

                  The Court entered judgment on the verdict and stipulated
contract damages in the amount of approximately $15,800 for a total judgment
amount of nearly $3.1 million plus interest. On September 26, 1997, Columbia
Transmission filed a motion for new trial, and on October 7, 1997, filed a
motion for remittitur to reduce the punitive damages in the judgment. On October
10, 1997, Columbia Transmission perfected an appeal. On October 29, 1997, the
Court denied Columbia Transmission's motion for remittitur. The Court ordered a
mediation process to be conducted in December 1997. As a result of the
mediation, Columbia Transmission and New Ulm settled the litigation and New
Ulm's claims for a proposed allowed amount of $2.25 million in December 1997,
subject to Columbia Transmission's Plan of Reorganization. The Bankruptcy Court
approved the settlement on January 26, 1998.

                  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
regarding a contract interpretation issue raised by both parties. Other issues
raised by New Bremen's claim and Columbia Transmission's response thereto were
referred to the claims mediator. 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 


                                       9
<PAGE>   11

ITEM 3. LEGAL PROCEEDINGS (Continued)

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.
District Court's grant of partial summary judgment in favor of Columbia
Transmission on the contract pricing issue. On February 3, 1997, the claims
mediator issued a recommendation as to issues not resolved by the decisions of
the U. S. District Court and the Fifth Circuit Court of Appeals. On February 25,
1997, Columbia Transmission filed a motion with the Bankruptcy Court seeking 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). Just prior to the hearing scheduled for April, 1997,
the Court advised the parties that it would review all submissions in connection
with the motion and advise the parties as to whether oral argument would be
required at a later date. To date, the Court has taken no further action
regarding Columbia Transmission's motion.

II.      Regulatory Matters

         A.   Matters that have been resolved

                  1. 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.
As reported in the Quarterly Report on Form 10-Q for the second quarter of 1997,
Columbia Transmission and the parties in this case reached a settlement, which
the FERC approved on June 25, 1997. No requests for rehearing were filed,
thereby concluding the proceeding. This matter is now concluded.

                  2. 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). As reported in the Quarterly Report on
Form 10-Q for the third quarter of 1997, Columbia Transmission and
Transcontinental Gas Pipeline Corporation ("Transco") reached an agreement to
settle a FERC Order No. 94 matter for a total payment to Transco of $5.4
million. On September 9, 1997, the Bankruptcy Court entered an order approving
the settlement agreement. Columbia Transmission has made the $5.4 million refund
to Transco as required by the settlement. Columbia Transmission and its Virginia
customers have subsequently agreed to a plan whereby Columbia Transmission and
the customers shared in the refund payment to Transco. The agreement resulted in
billings to these customers of approximately $1.9 million. This matter is now
concluded.

III.     Environmental

                  1. 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. Columbia Transmission continues to pursue
recovery of environmental expenditures from its insurance carriers, however, at
this time, management is unable to determine the total amount or final
disposition of any recovery.

                  2. 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. Columbia Gulf continues to pursue recovery 


                                       10
<PAGE>   12

ITEM 3. LEGAL PROCEEDINGS (Continued)

of environmental expenditures from its insurance carriers, however, at this
time, management is unable to determine the total amount or final disposition of
any recovery.

IV.      Other

                  A. Matters that have been resolved

                  1. 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). As reported in the Quarterly Report on Form 10-Q for the first
quarter of 1997, a settlement was reached in this matter in March 1997.

                  B. Pending Matters

                  1. 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.

                  A trial commenced in the third quarter of 1996 in the Court of
Queen's Bench, and was adjourned while the plaintiff sought to have Amoco's (a
co-defendant) 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. The trial resumed in September 1997. 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. As a
result of the 1997 upgrading of Columbia's long-term debt, an escrow account
that provides security for the indemnification obligation and is now funded by a
letter of credit was reduced to approximately $35,835,000 (Cdn).

                  2. Cathodic Protection. In September 1995, the management of
Commonwealth Gas Services, Inc. (now Columbia Gas of Virginia, Inc.) ("Columbia
of Virginia") advised the Staff of the Virginia State Corporation Commission
that there had been deficiencies in Columbia of Virginia'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 Columbia of Virginia to produce documents
related to its cathodic protection program in the Northern Operating Area.
Columbia of Virginia 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.


                                       11
<PAGE>   13


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 ColumEngy or ColumEgy in trading
reports. The number of shareholders on December 31, 1997, was approximately
37,698 and the stock closed at $78.5625, as reflected in the New York Stock
Exchange Composite Transactions as reported by The Wall Street Journal. On
February 18, 1998, Columbia declared a quarterly dividend of $0.25 per share for
the first quarter of 1998, which will be payable on or about March 16, 1998, to
holders of record on March 2, 1998.

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


                                       12
<PAGE>   14
ITEM 6. SELECTED FINANCIAL DATA

                            SELECTED FINANCIAL DATA

                     Columbia Energy Group and Subsidiaries

<TABLE>
<CAPTION>
($ in millions, except per share amounts)              1997           1996           1995*         1994*         1993*         1992*
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                 <C>            <C>            <C>           <C>           <C>           <C>
INCOME STATEMENT DATA ($)     
 Total operating revenues                           5,053.6        3,354.0        2,635.2       2,747.1       3,313.8       2,859.2
 Products purchased                                 3,138.1        1,481.1          820.6         984.2       1,577.7       1,236.9
 Earnings (Loss) before extraordinary item
  and accounting changes                              273.3          221.6         (432.3)        246.2         152.2          90.9
 Earnings (Loss) on common stock                      273.3          221.6         (360.7)        240.6         152.2          51.2
------------------------------------------------------------------------------------------------------------------------------------
PER SHARE DATA
 Earnings (Loss) per common share ($):
  Before extraordinary item and accounting changes     4.93           4.12          (8.57)         4.87          3.01          1.79
  Earnings (Loss) per common share                     4.93           4.12          (7.15)         4.76          3.01          1.01
 Average common shares outstanding (000)             55,405         53,792         50,477        50,563        50,563        50,563
 Diluted earnings (loss) per common share ($):
  Before extraordinary item and accounting changes     4.90           4.11          (8.57)         4.87          3.01          1.79
  Diluted earnings (loss) per common share             4.90           4.11          (7.15)         4.76          3.01          1.01
 Diluted average common shares (000)                 55,734         53,951         50,477        50,563        50,563        50,563
 Dividends:
  Per share ($)                                        0.90           0.60             -              -             -             -
  Payout ratio (%)                                     18.3           14.6           N/A            N/A           N/A           N/A
------------------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET DATA ($)
 Capitalization including debt
  subject to Chapter 11:                              
   Common stock equity                              1,790.7        1,553.6       1,114.0        1,468.0       1,227.3       1,075.1
   Preferred stock                                        -              -         399.9              -             -             -
   Long-term debt                                   2,003.5        2,003.8       2,004.5            4.3           4.8           5.4
   Short-term debt                                      N/A            N/A           N/A              -             -             -
   Current maturities of long-term debt                 0.5            0.8           0.5            1.2           1.3           1.4
   Debt subject to Chapter 11                             -              -             -        2,317.1       2,317.1       2,317.1
   Total                                            3,794.7        3,558.2       3,518.9        3,790.6       3,550.5       3,399.0
 Total assets                                       6,612.3        6,004.6       6,057.0        7,164.9       6,957.9       6,505.9
------------------------------------------------------------------------------------------------------------------------------------
OTHER FINANCIAL DATA
 Capitalization ratio (%) (including
  current maturities**):
   Common stock equity                                 47.2           43.7          31.7           38.7          34.6          31.6
   Preferred stock                                        -              -          11.4              -             -             -
   Debt                                                52.8           56.3          56.9           61.3          65.4          68.4
 Capital expenditures ($)                             560.3          314.8         421.8          447.2         361.3         299.7
 Net cash from operations ($)                         468.2          477.0        (804.1)         572.8         850.4         765.4
 Book value per common share ($)                      32.27          28.11         22.64          29.03         24.27         21.26
 Return on average common equity before
  extraordinary item and accounting changes (%)        16.3           16.6         (33.5)          18.3          13.2           8.7
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

N/A - Not applicable

Dilutive potential common shares were not included in the 1995 computation of
diluted EPS as the effect would be antidilutive.

* 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>   15
ITEM 6.   SELECTED FINANCIAL DATA

                            SELECTED FINANCIAL DATA

                     Columbia Energy Group and Subsidiaries
<TABLE>
<CAPTION>

($ in millions, except per share amounts)            1991*          1990           1989           1988           1987
----------------------------------------------------------------------------------------------------------------------
<S>                                            <C>            <C>            <C>            <C>            <C>
INCOME STATEMENT DATA ($)                                                                                       
  Total operating revenues                        2,463.7        2,346.7        3,189.3        3,157.5        2,855.7
  Products purchased                              1,056.5          846.8        1,669.0        1,822.3        1,534.2
  Earnings (Loss) before extraordinary item
   and accounting changes                          (794.8)         104.7          145.8          119.0          111.3
  Earnings (Loss) on common stock                  (694.4)         104.7          145.8          111.1          100.5
----------------------------------------------------------------------------------------------------------------------
PER SHARE DATA
  Earnings (Loss) per common share ($):
   Before extraordinary item and
    accounting changes                             (15.72)          2.21           3.21           2.46           2.30
   Earnings (Loss) per common share                (13.74)          2.21           3.21           2.46           2.30
  Average common shares outstanding (000)          50,537         47,326         45,511         45,210         43,787
  Diluted earnings (loss) per common share ($):
   Before extraordinary item and
    accounting changes                             (15.72)          2.21           3.19           2.46           2.29
   Diluted earnings (loss) per common share        (13.74)          2.21           3.19           2.46           2.29
  Diluted average common shares (000)              50,537         47,426         45,696         45,210         43,837
  Dividends:
   Per share ($)                                     1.16           2.20          2.00            2.29           3.18
   Payout ratio (%)                                   N/A           99.5          62.3            93.3          138.3
---------------------------------------------------------------------------------------------------------------------
BALANCE SHEET DATA ($)
 Capitalization including debt
  subject to Chapter 11:
  Common stock equity                             1,006.9        1,757.8        1,620.3        1,552.6        1,523.7
  Preferred stock                                       -              -              -              -          110.0
  Long-term debt                                      6.1        1,428.7        1,196.0        1,038.4        1,438.0
  Short-term debt                                     N/A          735.5          634.2          697.1          327.5
  Current maturities of long-term debt                2.9           35.2           47.2           52.7           69.6
  Debt subject to Chapter 11                      2,317.1              -              -              -              -
  Total                                           3,333.0        3,957.2        3,497.7        3,340.8        3,468.8
 Total assets                                     6,332.2        6,196.3        5,878.4        5,641.0        5,440.9
----------------------------------------------------------------------------------------------------------------------
OTHER FINANCIAL DATA
 Capitalization ratio (%) (including
  current maturities**):
   Common stock equity                              30.2           44.4           46.3            46.5           43.9
   Preferred stock                                     -              -              -               -            3.2
   Debt                                             69.8           55.6           53.7            53.5           52.9
 Capital expenditures ($)                          381.9          629.6          473.5           307.9          298.8
 Net cash from operations ($)                      531.6          420.1          400.5           429.4          702.0
 Book value per common share ($)                   19.92          34.83          35.50           34.18          34.08
 Return on average common equity
  before extraordinary item
  and accounting changes (%)                        N/A             6.2            9.2             7.7            7.5
----------------------------------------------------------------------------------------------------------------------
</TABLE>
N/A - Not Applicable

Dilutive potential common shares were not included in the 1995 computation of
diluted EPS as the effect would be antidilutive.

*    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 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.















                                       14
<PAGE>   16


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


Index                                                                       Page
--------------------------------------------------------------------------------
Consolidated Review......................................................    15
Liquidity and Capital Resources..........................................    17
Transmission and Storage Operations......................................    21
Distribution Operations..................................................    26
Exploration and Production Operations....................................    32
Marketing, Propane and Power Generation Operations.......................    35
Bankruptcy Matters.......................................................    38
--------------------------------------------------------------------------------

The Management's Discussion and Analysis, including statements regarding market
risk sensitive instruments, 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. Investors and prospective investors 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 statements concerning Columbia's plans,
objectives, expected performance, expenditures and recovery of expenditures
through rates, stated on either a consolidated or segment basis, and including
any and all underlying assumptions and other statements that are other than
statements of historical fact. From time to time, Columbia may publish or
otherwise make available forward-looking statements of this nature. All such
subsequent forward-looking statements, whether written or oral and whether made
by or on behalf of Columbia, are also expressly qualified by these cautionary
statements. All 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 and
commodity market conditions many of which are beyond the control of Columbia. In
addition, the relative contributions to profitability by segment, and the
assumptions underlying the forward-looking statements relating thereto, may
change over time due to changes in the marketplace.

With respect to any references made to ratings assigned to Columbia's debt
securities, there can be no assurance that Columbia will be successful at
maintaining its credit quality 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.

                               CONSOLIDATED REVIEW

Net Income

Columbia's 1997 record-setting net income was $273.3 million, or $4.93 per
share. Net income was up $51.7 million, or 81 cents per share, over 1996 due in
large part to lower operating costs for the regulated subsidiaries and increased
revenues from transportation and storage services and gas management activities.
This improvement was achieved despite weather that was 4% warmer than 1996. The
weather difference reduced 1997 net income by $15.2 million compared to 1996.

Several nonrecurring items also impacted the results of both years.
Restructuring activities reduced net income in 1997 by $20.2 million and in 1996
by $35.7 million. Current period results were improved by a $12.8 million
reduction to tax expense resulting from benefits gained through the filing of a
consolidated state tax return, a $6 million after-tax gain from the sale of coal
assets and a $5.5 million gain on the temporary deactivation of a storage field.
The 1996 results benefited from a $5.6 million favorable adjustment to the 1995
sale of Columbia's southwest gas and oil subsidiary.

Revenues

Operating revenues for 1997 were $5,053.6 million, an increase of $1,699.6
million over 1996. The higher revenues were principally due to increased sales
by the gas marketing subsidiary, Columbia Energy Services Corporation (Columbia
Energy Services), and higher rates in effect for the distribution subsidiaries
for the recovery of increased gas costs. Also improving revenues were the
effects of regulatory settlements reached in 1997 for Columbia Gas Transmission
Corp. (Columbia Transmission) and Columbia Gas of Ohio, Inc. (Columbia of Ohio)
and increased off-system sales, transportation and storage services. Tempering
these improvements were lower 


                                       15
<PAGE>   17

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

sales volumes in 1997 compared to 1996 for the distribution subsidiaries related
to warmer weather and lower wellhead prices for gas production.

In 1996, operating revenues of $3,354 million reflected an increase of $718.8
million over 1995 primarily due to additional sales by the gas marketing and
distribution subsidiaries. Also increasing revenues in 1996 were higher gas
prices that increased both the gas commodity portion of the distribution
subsidiaries' rates and prices received for gas production as well as the effect
of colder weather experienced in early 1996. Higher base rates in effect for the
regulated subsidiaries also increased revenues $68.7 million. In 1995, revenues
included $96.1 million from Columbia's former southwest gas and oil subsidiary,
that was sold effective year end 1995, as well as $12.2 million of exit fee
payments received by Columbia Gulf Transmission Company (Columbia Gulf). Exit
fee payments were paid to Columbia Gulf by certain of its customers as
compensation for terminating their transportation agreements before the
scheduled expiration date.

Expenses

Operating expenses for 1997 of $4,544.2 million were $1,668.4 million higher
than 1996. This increase reflected $1,657 million higher product purchased
expense attributable to gas purchased by Columbia Energy Services to meet sales
requirements and the higher cost of gas purchased by the distribution
subsidiaries. Despite acquisitions made in 1997 and higher startup costs for new
services, Columbia's 1997 operation and maintenance expense decreased $3.6
million from 1996. Operation and maintenance expense for the Marketing, Propane
and Power Generation segment rose $22.4 million due in large part to expanding
the marketing operations through the acquisition of PennUnion Energy Services
L.L.C. (PennUnion) and building Columbia Energy Services' infrastructure to
support its growth. Also contributing to higher costs was the 1997 acquisition
of Alamco, Inc. (Alamco), an Appalachian exploration and production company.
Operation and maintenance costs for the regulated subsidiaries decreased, after
adjusting for nonrecurring items, reflecting the beneficial effect of
implementing restructuring initiatives. These nonrecurring items included a
$10.1 million reserve for the anticipated sale of certain pipeline facilities;
restructuring charges recorded in both years; a $5.3 million period-to-period
improvement for FERC Order No. 94 adjustments, an environmental reserve addition
in 1997 and the costs of a risk management program for Columbia of Ohio and
Columbia Gas of Kentucky, Inc. (Columbia of Kentucky), designed to mitigate
potential adverse effects of certain future business risks.

In 1996, operating expenses of $2,875.8 million increased $630.8 million over
1995 reflecting a $660.5 million increase in products purchased primarily to
meet additional sales requirements. Operation and maintenance expense increased
$22.6 million and included restructuring costs of $54.9 million in 1996 and $5.8
million in 1995. Expenses in 1995 also included $39.1 million associated with
the operations of Columbia's former southwest gas and oil subsidiary. After
adjusting for restructuring charges, operation and maintenance expense was down
approximately $30 million in 1996. Depreciation and depletion expense decreased
$54.8 million primarily as a result of reduced depletable plant due to the sale
of Columbia's southwest gas and oil subsidiary and a lower depletion rate
attributable to higher gas prices.

Other Income (Deductions)

<TABLE>
<CAPTION>
Twelve Months Ended December 31 (in millions)     1997      1996        1995
--------------------------------------------------------------------------------
<S>                                             <C>       <C>         <C>       
   Interest income and other, net               $  40.4   $   26.1    $   (58.2)
   Interest expense and related charges          (157.6)    (166.8)      (988.4)
   Reorganization items, net                         --         --         13.4
--------------------------------------------------------------------------------
   Total Other Income (Deductions)              $(117.2)  $ (140.7)   $(1,033.2)
--------------------------------------------------------------------------------
</TABLE>

Other Income (Deductions) reduced income $117.2 million in 1997 and $140.7
million in 1996. The improvement was largely due to $3.5 million of reduced
interest expense on short-term borrowings, an $8.5 million pre-tax gain for the
payment received from a coal company related to the deactivation of a storage
field to allow the mining of coal reserves as well as increased interest income
on temporary cash investments. Also in 1997, Columbia's coal assets were sold
which improved pre-tax income approximately $9.5 million. In the second quarter
of 1996, an $8.6 million pre-tax favorable adjustment was recorded for the 1995
sale of Columbia's southwest gas and oil subsidiary. Interest income and other,
net, in 1996 included approximately $13.5 million for Order 94 refunds that was
offset in interest expense and related charges with no effect on income.


                                       16
<PAGE>   18

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

When comparing 1996 to 1995, Other Income (Deductions) reduced income $140.7
million in 1996, compared to a decrease in income of $1,033.2 million in 1995.
The principal reason for the $988.4 million decrease in 1995's income for
interest expense and related charges was $983 million of prepetition debt
obligations recorded at emergence from bankruptcy in November 1995. Interest
income and other, net, of $26.1 million in 1996 included the adjustment recorded
for the sale of Columbia's southwest gas and oil subsidiary; $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 for 1996 reflected $140.4 million of interest expense on
long-term debt and $11.7 million of interest expense on short-term debt
obligations. Interest expense in 1996 also included $3.9 million of interest on
rate refunds recorded by the rate regulated subsidiaries.

Income Taxes

Income tax expense in 1997 of $118.9 million increased only $3 million over the
year earlier despite $54.7 million higher taxable income. This was due in large
part to a $12.8 million reduction to tax expense resulting from benefits gained
through the filing of a consolidated state tax return. The change in taxable
income was the primary reason for the variance in income tax expense between
1996 and 1995.

Extraordinary Item

In 1995, Columbia recorded an extraordinary after-tax gain of $71.6 million for
the cumulative adjustment for the reapplication of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation," (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 the recording of
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
the 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 are subject to seasonal
fluctuations in cash flow. During the heating season, which is primarily 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 short-term and long-term financing as
needed, are used to purchase gas to place in storage for heating season
deliveries, perform necessary maintenance of facilities, make capital
improvements in plant and expand service into new areas.

For 1997, net cash from operations was $468.2 million, a decrease of $8.8
million from the same period in 1996 primarily reflecting higher cash needs for
working capital purposes. During 1997, $90.3 million of additional cash was
invested in working capital, compared to $41.4 million of additional cash in
1996. Before these working capital changes, long-term cash flow from operations
was $558.5 million in 1997, compared to $518.4 million in 1996, an increase of
$40.1 million. The increase was primarily due to the $51.7 million increase in
net income during the year. The increased use of cash for working capital during
1997 was caused by higher accounts receivable, offset by lower income tax
refunds receivable and a switch from being underrecovered to overrecovered for
the distribution subsidiaries' gas costs. Tempering these uses of cash was the
full period effect of higher base rates for Columbia Transmission and Columbia
of Kentucky.

The rise in gas prices in 1996 resulted in an increase in the commodity portion
of the distribution subsidiaries' rates as provided for under the current
regulatory process, resulting in a higher recovery level of gas costs in 1997.
As of year end 1996, the distribution subsidiaries were in an underrecovered
position because the rapid increase in the cost of gas exceeded the recovery
levels that were allowed. The distribution subsidiaries were in an overrecovered
position as of year end 1997.

After adjusting the 1995 deficit for emergence payments, net cash from
operations in 1996 decreased $168.9 million from 1995 to $477 million. Cash in
1996 was lower than 1995 due to the lag in recovering gas costs by the
distribution subsidiaries in 1996 stemming from a rise in prices that exceeded
the distribution subsidiaries' then current recovery levels. Also reducing cash
in 1996 from 1995 was the effect of a higher average cost of gas placed in
storage. This decrease was partially offset by the working capital improvement
for income tax refunds of $271.5 


                                       17
<PAGE>   19

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

million, the favorable impact of colder weather in 1996 on the distribution
subsidiaries, and higher base rates in effect for the regulated subsidiaries.

Financing Activities

Columbia satisfies its liquidity requirements through internally generated funds
and the use of two unsecured bank revolving credit facilities that total $1.35
billion (Credit Facilities). The Credit Facilities were established in March
1998, and replaced the $1 billion five-year revolving credit facility entered
into by Columbia in November 1995. The Credit Facilities also support Columbia's
recently established commercial paper program.

Columbia's $1.35 billion Credit Facilities consist of a $900 million five-year
revolving credit facility and a $450 million 364-day revolving credit facility
with a one-year term loan option. The five-year facility will provide for the
issuance of up to $300 million of letters of credit.

As of December 31, 1997, Columbia had $120 million of short-term debt and
approximately $42.7 million of letters of credit outstanding under the prior
credit facility. Under Columbia's commercial paper program, $208.8 million was
outstanding at December 31, 1997. There were no commercial paper borrowings in
1996.

Interest rates on borrowings under the Credit Facilities are based upon the
London Interbank Offered Rate, Certificate of Deposit rates or other short-term
interest rates. The interest rate margins and facility fees on the commitment
amount are based on Columbia's public debt ratings. In 1997, Fitch Investors
Service, Moody's Investors Service, Inc. and Standard & Poor's Ratings Group
upgraded Columbia's long-term debt rating to BBB+, Baa1 and BBB+, respectively.
Under the Credit Facilities, higher debt ratings result in lower facility fees
and interest rates on borrowings. Columbia's commercial paper credit ratings are
F-2 by Fitch, P-2 by Moody's and A-2 by S&P.

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 prior
credit facility and to retire $400 million of preferred stock issued in late
1995. No further issuances of the remaining $750 million available under the
shelf registration are scheduled at this time.

Management believes that its sources of funding are sufficient to meet
short-term and long-term liquidity needs not met by cash flows from operations.

Capital Expenditures

The table below reflects actual capital expenditures by segment for 1997 and
1996 and an estimate for 1998:

<TABLE>
<CAPTION>
(in millions)                                          1998      1997       1996
--------------------------------------------------------------------------------
<S>                                                    <C>       <C>        <C> 
  Transmission and Storage                             $250      $245       $143
  Distribution                                          162       159        148
  Exploration and Production                             86       136*        12
  Marketing, Propane and Power Generation                46        15          6
  Corporate                                              11         5          6
--------------------------------------------------------------------------------
  Total                                                $555      $560       $315
--------------------------------------------------------------------------------
</TABLE>

* Does not reflect approximately $23 million of gathering facilities that
  Columbia Transmission sold to Columbia Natural Resources, Inc.

For 1997, capital expenditures were $560 million, an increase of $245 million
over 1996. The Alamco acquisition in 1997 represented approximately $101 million
of the increase. In addition, the 1997 program included $118 million for market
expansion activities in the transmission and storage segment. The largest
portion of the transmission and storage segment's investments are made to ensure
the safety and reliability of the pipelines and for market expansion activities.
The distribution subsidiaries' program includes investments to extend service to
new areas and develop future markets, as well as expenditures required to ensure
safe, reliable and improved service.


                                       18
<PAGE>   20

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

For 1998, capital expenditures of $555 million are expected to be essentially
the same as the 1997 program. Included in the 1998 program is approximately $86
million for market expansion initiatives for the transmission and storage
segment and an additional $65 million is planned for new business and
development activities for the distribution segment. The 1998 program also
includes an increase in the Marketing, Propane and Power Generation segment for
additional investment in Columbia Energy Services' infrastructure. The principal
reason for the increase in the corporate segment was expenditures associated
with the new corporate headquarters, scheduled for completion in the fall of
1998.

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.

Market Risk Exposure

Subsidiaries in Columbia's production, marketing and propane operations are
exposed to market risk due to fluctuations in commodity prices. In order to help
minimize this risk, Columbia engages in commodity hedging activities to help
ensure stable cash flows, favorable prices and margins as well as to help
capture any long-term increases in value. Financial instruments utilized by
Columbia for commodity hedging include futures, swaps and options. Columbia
Natural Resources, Inc. (Columbia Resources) utilizes financial instruments to
fix prices for a portion of its future production volumes. These positions are
hedged in the marketplace through a gas marketing subsidiary. Columbia Energy
Services utilizes financial instruments to help assure adequate margins on the
purchase and resale of natural gas. Columbia Propane utilizes financial
instruments to help protect the value of inventories. Therefore, any losses or
gains on the physical transactions are largely offset by gains or losses on
these financial trades.

Columbia's current risk management program allows the subsidiaries to use
derivative instruments for hedging purposes only. In addition, Columbia employs
multiple risk control mechanisms to mitigate market risk, including volumetric
limits. For the gas marketing operations, where most of Columbia's derivative
activity occurs, its market risk at year end 1997 was computed using a value at
risk methodology. Value at risk simulates forward price curves in the energy
markets to estimate the size and probability of future potential losses. The
year end value at risk calculation was based on a 95% confidence interval and a
two-day time horizon. Loss is defined in the calculation as fair market value
loss. As of December 31, 1997, the value at risk for Columbia's market risk
sensitive instruments was immaterial.

Restructuring Activities

In 1997, approximately $31.1 million of pre-tax expense was recorded to reflect
restructuring-related costs, primarily for relocation, severance and benefits.
This restructuring initiative began in 1995 to streamline operations and make
them more efficient and cost-competitive. During 1996, $54.9 million pre-tax was
recorded for similar restructuring activities. The beneficial effect of
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 realizing 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. The project was
substantially completed at year end 1997 and resulted in the total number of
employees System-wide decreasing approximately 15% from the year-end 1995 level
of nearly ten thousand.

1997 Acquisitions

Columbia's strategic goal is to increase its investment in non-rate regulated
(nonregulated) businesses to a level that would provide for such operations to
contribute approximately 30% of Columbia's consolidated operating income by
2002. Consistent with this objective, Columbia Energy Services purchased
PennUnion in 1997, an energy-marketing affiliate of Pennzoil Company, for
approximately $14.75 million, subject to certain working capital and other
adjustments. In addition, Columbia Resources acquired Alamco, an Appalachian gas
and oil exploration and development company, for approximately $101 million. For
additional information on the Alamco acquisition, see the Exploration and
Production segment, and see the Marketing, Propane and Power Generation segment
for a further discussion of the PennUnion acquisition. Columbia continually
evaluates acquisition and strategic alliance opportunities made available to it
by the marketplace. However, it is Columbia's general policy not to comment on
the specifics of any such opportunity.


                                       19
<PAGE>   21

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

Impact of Year 2000 on Computer Systems

The Year 2000 issue is a world-wide concern that many existing computer programs
were initially designed without considering the impact of the change to the year
2000. This could result in the programs incorrectly identifying dates in the
year 2000. If not corrected, certain applications could fail or create erroneous
results.

Columbia is currently in the process of reviewing its computer applications and
their interaction with third parties to address the Year 2000 issue. Based on
the review to date, certain applications have been found that are not Year 2000
compliant. It is anticipated that all major applications will have been reviewed
and, if necessary, corrected or replaced by the year 2000.

At the present time, management does not anticipate that the cost of correcting
or replacing those applications that are not Year 2000 compliant will have a
material impact on Columbia's financial condition.

Common Stock Prices and Dividends

<TABLE>
<CAPTION>
                                                             Market Price
                                   --------------------------------------------------------------
<S>                               <C>                           <C>                        <C>                   <C>
                                                                                                                   Quarterly
Quarter Ended                        High                         Low                       Close                Dividends Paid
-----------------------------------------------------------------------------------------------------------------------------------
                                      $                            $                          $                        $
1997 
December 31                        78 5/8                        69 1/2                    78 9/16                     .25
September 30                       72 1/4                        65 3/16                   70                          .25
June 30                            67 3/8                        56                        65 1/4                      .25
March 31                           65 7/8                        57 5/8                    57 7/8                      .15
-----------------------------------------------------------------------------------------------------------------------------------
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
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>









                                       20
<PAGE>   22

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


                       TRANSMISSION AND STORAGE OPERATIONS


Proposed Millennium and Vector Pipeline Projects

The proposed Millennium Pipeline Project, in which Columbia Transmission is
participating and will serve as developer and operator, will transport western
gas supplies to Northeast and Mid-Atlantic markets. The 442-mile pipeline will
connect to TransCanada Pipe Lines Ltd. at a new Lake Erie export point and
transport up to approximately 700,000 Mcf per day to eastern markets. Eight
shippers have agreements for the available capacity. A filing with the FERC
requesting approval of the Millennium Project, was made on December 22, 1997.
This filing begins the extensive review process, including opportunities for
public review, communication and comment. On February 3, 1998, the FERC issued a
Notice of the Millennium Application which provided that any person desiring to
participate in the hearing process or make any protest to the application
should, on or before February 24, 1998, file with the FERC a motion to intervene
or a protest in accordance with FERC regulations. Several interventions were
submitted to the FERC by interested parties. On. March 9, 1998, Columbia
Transmission filed with the FERC a response to the interventions. The proposed
in-service date is November 1999. Columbia Transmission will continue its
ongoing assessment of the project's schedule into the second quarter of 1998.

The current sponsors of the proposed Millennium Project are Columbia
Transmission, Westcoast Energy, Inc., TransCanada Pipe Lines Ltd., and MCN
Energy Group, Inc.

Columbia Transmission is in discussions with IPL Energy Inc. to become a sponsor
of the proposed Vector Pipeline project to transport western gas supplies from
Chicago to the Ontario area. The proposed Vector Pipeline would provide one of
several upstream links for Columbia Transmission's proposed Millennium Pipeline.

Market Expansion Project

After receiving final FERC approval, Columbia Transmission began construction on
the expansion of its pipeline and storage systems during 1997 to meet increased
customer demand. The first phase of service began in November 1997. Upon
completion, which is expected in 1999, the expansion will add approximately
500,000 Mcf per day of firm service to 23 customers.

The New York State Electric & Gas Corporation (NYSEG) filed an appeal to the
expansion project with the U. S. Court of Appeals for the District of Columbia
Circuit, primarily to challenge the FERC's approval of rolled-in pricing for the
market expansion service levels. NYSEG has not requested a stay of Columbia
Transmission's certificate order. Accordingly, construction is proceeding.

Competition and the Effect of LDC Unbundling Services

The transmission subsidiaries compete with other interstate pipelines for the
transportation and storage of natural gas. Furthermore, since the issuance of
Order No. 636, various states throughout Columbia Transmission's service area
have initiated proceedings dealing with open access and unbundling of local
distribution companies' (LDC) services. Among other things, unbundling involves
providing all LDC customers with the choice of what entity will serve as the
merchant supplier, a role historically filled by the LDC. While the scope and
timing of these various unbundling initiatives varies from state to state,
retail choice programs are being extended to increasing numbers of LDC customers
throughout Columbia Transmission's market area.

Among the issues being addressed in the state unbundling proceedings is the
treatment of the pipeline transmission and storage agreements which have
underpinned the traditional LDC merchant function. In the case of Columbia
Transmission and Columbia Gulf, contracts covering the majority of their firm
transportation and storage quantities with LDCs have primary terms which extend
to October 31, 2004. Management fully expects that the LDCs, or those entities
to which pipeline capacity may be assigned as a result of the LDC unbundling
process, will continue to fulfill their obligations under these agreements.
However, in view of the changing market and regulatory environment, the
transmission companies have commenced the process of discussing long-term
transportation and storage service needs with their firm customers. While those
discussions could result in the restructuring of some of these contracts on
mutually agreeable terms prior to 2004, it is not possible to predict the
results of those discussions at this time.

Although the specific outcome of these capacity issues is uncertain, at this
time, management does not believe that it will have a material impact on
Columbia's financial condition.


                                       21
<PAGE>   23

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

Regulatory Matters

                           Columbia Gulf's Rate Filing

Columbia Gulf filed a general rate case on October 31, 1996, which became
effective on May 1, 1997, subject to refund. An agreement in principle settling
all issues and rate levels in Columbia Gulf's rate proceedings was reached in
January 1998. Active parties in the proceeding have unanimously agreed to the
terms of the settlement. On March 3, 1998, a written offer of settlement was
filed with the FERC. Columbia Gulf anticipates that the settlement will be
approved without any modification by the end of the second quarter of 1998.
Management believes that if the settlement is approved as presently written, it
will not have a material impact on Columbia's financial statements which include
an adequate reserve for the settlement.

                   Columbia Gulf Main-line Capacity Proceeding

In September 1993, the FERC directed Columbia Gulf to show cause as to why it
had not filed for FERC abandonment authorization to reduce capacity on its
mainline facility. Since that time, Columbia Gulf has responded to various
information requests from the FERC. In an August 8, 1997 order, the FERC
approved a settlement, which required Columbia Gulf to conduct a 30-day open
season on additional firm mainline capacity up to its certificated design.
Although certain of Columbia Gulf's customers challenged the terms of the
settlement, Columbia Gulf concluded the open season on December 15, 1997, which
resulted in requests for capacity that exceeded the capacity specified in
Columbia Gulf's FERC certificate. The challenges remain pending at the FERC.

                Columbia Transmission's Phase II Rate Proceeding

Columbia Transmission's rate case settlement, approved by the FERC in April
1997, excluded the environmental cost recovery issue. A hearing to address this
issue is currently scheduled for the fall of 1998. Pending the outcome of this
proceeding, Columbia Transmission continues to collect approximately $18 million
per year, subject to refund, for environmental costs.

                Challenge to Columbia Transmission's Rate Design

Pursuant to a provision of Columbia Transmission's 1997 rate settlement, the New
York Public Service Commission (NYPSC) had the right to initiate a hearing
challenging the appropriateness of the Straight Fixed Variable (SFV) rate design
for Columbia Transmission. The NYPSC exercised its right to a hearing, which is
currently scheduled for late 1998. Any change from the current SFV methodology
would be placed into effect no earlier than February 1, 2000.

Sale of Gathering Facilities

Effective September 1, 1997, Columbia Transmission sold approximately 2,700
miles of gathering lines to Columbia Resources for approximately $23 million,
with an additional 750 miles anticipated to be sold to Columbia Resources by the
second quarter of 1998. In addition, approximately 1,800 miles of gathering
lines and facilities in Ohio were sold to Gatherco, Inc., effective October 31,
1997. The majority of the remaining 800 miles of gathering lines are expected to
be sold to other parties during 1998.

Capital Expenditure Program

The transmission and storage segment's net capital expenditure program was
approximately $245 million in 1997 and is projected to be $250 million in 1998.
Market expansion initiatives totaled approximately $118 million in 1997 and $86
million is anticipated in 1998. The remaining expenditures are for modernizing
and upgrading facilities.

Restructuring and Relocation Activities

Columbia Transmission and Columbia Gulf began a restructuring project in early
1996 to streamline the business functions and improve productivity by focusing
on all processes within the transmission companies. In 1996, the implementation
of key recommendations began and continued throughout 1997. In addition, during
1997 certain staff and management positions were relocated to Northern Virginia.
In 1997, approximately $24.3 million was recorded for restructuring and
relocation costs.

Environmental Matters

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


                                       22
<PAGE>   24

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

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.

Columbia Transmission received EPA approval for and completed characterization
activities for 73 major facilities, approximately 2,800 liquid removal points
and approximately 900 mercury measurement stations in 1997. In addition,
approximately 400 mercury measuring stations were remediated.

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.
Columbia Transmission conducted assessments at 160 sites and based on these
assessment results, performed remedial activities in varying degrees at
approximately 85 locations.

As a result of these 1997 activities, Columbia Transmission recorded an
additional liability of $16.8 million. Actual expenditures of approximately
$17.1 million during 1997 charged to the liability resulted in a remaining
liability of $125.4 million. Columbia Transmission's environmental cash
expenditures are expected to be approximately $18 million in 1998 and up to $20
million annually until the AOC is satisfied. These expenditures will be charged
against Columbia Transmission's previously recorded liability. Consistent with
Statement of Financial Accounting Standards No. 71, a regulatory asset has been
recorded to the extent environmental expenditures are expected to be recovered
through rates. Columbia Transmission continues to pursue recovery of
environmental expenditures from its insurance carriers; however, at this time,
management is unable to determine the total amount or final disposition of any
recovery. 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, 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. At this time Columbia Transmission is unable to determine if it will
become liable for any characterization or remediation costs at such sites.


                                       23
<PAGE>   25

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

Throughput

Columbia Transmission's throughput consists of transportation and storage
services for local distribution companies and other customers within its market
area. Throughput for Columbia Gulf reflects mainline transportation services
from Rayne, 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 1,301.5 Bcf
for 1997, a decrease of 76.6 Bcf from 1996 primarily due to warmer weather in
Columbia Transmission's operating territory. Total throughput for 1996 was
1,378.1 Bcf, an increase of 41.9 Bcf from 1995. The colder weather in 1996
contributed to increased demand as well as increased marketing efforts on
Columbia Gulf's system.

Columbia Transmission's market area transportation declined 69.8 Bcf to 1,032.6
Bcf during 1997 largely due to the 5% warmer weather in the first quarter and
lower summer-related requirements from electric cogeneration facilities. Total
throughput for 1996 of 1,102.4 Bcf declined 3.7 Bcf from 1995 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.

Mainline transportation for Columbia Gulf decreased 26.2 Bcf to 607.5 Bcf in
1997, reflecting the impact of warmer weather in Columbia Transmission's
operating territory. During 1996, mainline transportation increased 28.7 Bcf
from 1995 due to the colder weather during the 1995-1996 winter heating season.
As a result, Columbia Gulf's mainline services were heavily utilized during the
summer of 1996 to refill depleted gas inventories on Columbia Transmission's
storage system in preparation for the 1996-1997 winter heating season.

Columbia Gulf's short-haul transportation decreased 14.1 Bcf from 1996 to 252.4
Bcf in 1997 largely due to a decline in market demand in the area south of
Rayne, Louisiana. An increase in short-haul transportation of 45.1 Bcf in 1996
over 1995 reflected increased production and new sources of offshore supply as
well as new interconnections in Louisiana.

Operating Revenues

Operating revenue of $849.8 million in 1997 increased $39 million over the
previous year. After adjusting for the recovery of upstream transportation costs
and certain other revenues that are fully offset in operating expense, current
operating revenues increased $28 million. This increase was largely due to the
sale of certain base gas volumes that were part of Columbia Transmission's
overall rate case settlement which became effective in the second quarter.
Increased revenues from transportation and storage services also contributed to
the improvement. Tempering these improvements were reduced revenues attributable
to a lower cost-of-service level underlying Columbia Transmission's rates in
1997. During the first quarter of 1998, an additional 5 Bcf of base gas is
anticipated to be sold under the terms of Columbia Transmission's rate case
settlement.

Operating revenue increased $50.5 million to $810.8 million in 1996. After
adjusting for recovery items mentioned above, operating revenue increased $37.7
million over 1995. This increase was primarily due to the new rates in place for
Columbia Transmission effective February 1, 1996. This increase was partially
offset by recognizing $12.2 million in exit fees collected by Columbia Gulf in
1995.

Operating Income

Operating income for the transportation and storage segment for 1997 was $264.3
million, an increase of $56.5 million over 1996. This improvement is
attributable to $39 million higher operating revenues, as discussed previously,
and $17.5 million lower operating expense. Operation and maintenance expense
declined $10.4 million primarily reflecting lower restructuring costs and
savings achieved through the implementation of restructuring initiatives. In
addition, operation and maintenance expense declined $5.4 million due to the
effects in 1997 and 1996 of a 1980's issue regarding production-related costs.
Columbia LNG Corp. contributed to 1997 results an additional $4.3 million over
1996, primarily reflecting a higher level of peaking services for new and
existing customers. Tempering these improvements were higher 1997 expense of
$10.1 million to reflect a valuation reserve for the anticipated sale of certain
pipeline facilities and an increase in the environmental reserve.

Operating income decreased $5.2 million to $207.8 million in 1996 from 1995
primarily as a result of a $55.7 million increase in operating expenses
partially offset by the increase in revenues mentioned above. This increase was


                                       24
<PAGE>   26

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

primarily the result of restructuring charges and employee incentive awards.
These decreases to operating income were tempered by a $2.8 million improvement
for Columbia LNG, reflecting its first full year of commercial operations.

          STATEMENTS OF OPERATING INCOME FROM TRANSMISSION AND
                         STORAGE OPERATIONS (UNAUDITED)
<TABLE>
<CAPTION>
Year Ended December 31 (in millions)                                             1997                   1996                  1995
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>                    <C>                   <C>
OPERATING REVENUES
 Transportation revenues                                                        $622.0                 $629.0                $612.7
 Storage revenues                                                                179.8                  159.5                 139.3
 Other revenues                                                                   48.0                   22.3                   8.3
-----------------------------------------------------------------------------------------------------------------------------------
 Total Operating Revenues                                                        849.8                  810.8                 760.3
-----------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
 Operation and maintenance                                                       428.3                  444.1                 392.5
 Depreciation                                                                    104.3                  102.6                 103.8
 Other taxes                                                                      52.9                   56.3                  51.0
-----------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses                                                         585.5                  603.0                 547.3
-----------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME                                                                $264.3                 $207.8                $213.0
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

                 TRANSMISSION AND STORAGE OPERATING HIGHLIGHTS

<TABLE>
<CAPTION>
                                                 1997              1996               1995                1994                1993
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                          <C>               <C>                <C>                 <C>                 <C>
CAPITAL EXPENDITURES ($ in millions)            244.9             142.7              172.5               179.1               137.2
-----------------------------------------------------------------------------------------------------------------------------------
THROUGHPUT (Bcf)
Transportation
 Columbia Transmission
  Market area                                 1,032.6           1,102.4            1,106.1             1,038.6               895.9
 Columbia Gulf
  Main-line                                     607.5             633.7              605.0               590.3               579.9
  Short-haul                                    252.4             266.5              221.4               225.4               258.1
  Intrasegment eliminations                    (591.0)           (624.5)            (596.3)             (583.2)             (561.7)
-----------------------------------------------------------------------------------------------------------------------------------
Total Transportation                          1,301.5           1,378.1            1,336.2             1,271.1             1,172.2
Sales                                               -                 -                  -                 0.9               183.7
-----------------------------------------------------------------------------------------------------------------------------------
Total Throughput                              1,301.5           1,378.1            1,336.2             1,272.0             1,355.9
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
   


                                     25

<PAGE>   27

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


                             DISTRIBUTION OPERATIONS

Market Conditions

Weather during 1997 was 4% warmer than 1996 in the market area served by
Columbia's distribution companies (Distribution) and, as a result,
Distribution's weather-sensitive deliveries were down 15 Bcf compared to 1996.
In addition, a 10-month labor strike shut down production at a major customer,
causing a 7 Bcf decline in usage compared to 1996. Although warmer than 1996,
1997's weather was 2% colder than normal. There were some notable weather
fluctuations in 1997, which had the fifth warmest February and the second
coldest April/May period since 1950.

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. The northern Ohio and Pittsburgh, Pennsylvania areas 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% of Distribution's industrial and commercial throughput, or 128
Bcf, is susceptible to bypass, because these customers are 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
customer arrangements, substantial inroads by other natural gas competitors have
been avoided to date. As a result, the estimated throughput exposure to bypass
has been reduced to approximately 43 Bcf, representing about $11 million in
annual net revenue.

Regulatory Matters

On January 7, 1998, the Public Utilities Commission of Ohio (PUCO) approved a
second amendment to Columbia of Ohio's 1994 rate case. The amendment was filed
in November 1997 by Columbia of Ohio and a group comprising diverse interested
parties, also known as the Collaborative. The amendment establishes a five-year
funding mechanism that will enable Columbia of Ohio to expand its Customer
CHOICE(R) transportation program for residential and small commercial customers
statewide in 1998. The funding mechanism authorizes Columbia of Ohio to use
off-system sales, capacity release revenues and fees collected from marketers to
offset the cost of transition capacity that may be generated by expansion of the
Customer CHOICE(R) program, while simultaneously providing Columbia of Ohio with
an opportunity to retain some of the capacity release and off-system sales
revenues along with the benefit of reductions to upstream capacity charges. The
amendment to the settlement also extends by one year, to January 1, 2000,
Columbia of Ohio's commitment not to file a base rate increase.

Although the amendment approves the funding mechanism to expand the Customer
CHOICE(R) program statewide, the Collaborative will meet in early 1998 to
discuss operationally-oriented program modifications that may be necessary or
desirable to expand the program. Any modifications will be submitted to the PUCO
for approval, and it is anticipated that the program will be expanded throughout
Ohio in the second half of 1998.

The amendment gives Columbia of Ohio the responsibility to manage the transition
pipeline capacity costs that will arise as residential and small commercial
customers elect to acquire the commodity directly from marketers participating
in the Customer CHOICE(R) program, and revenue streams from a number of sources
including off-system sales and capacity releases with which to manage this
responsibility. Columbia of Ohio has accepted the risk for up to 11% of the
transition capacity costs to the extent these costs exceed the revenue streams
available to offset them. However, if after the conclusion of the five year
program, the revenues from these sources more than offset the transition
capacity costs, then customers and Columbia of Ohio will share the credit
balance, 75% to the customers and 25% to Columbia of Ohio.

Distribution continues to pursue initiatives that give retail customers the
opportunity to purchase natural gas directly from marketers and to use
Distribution's facilities for transportation service. These opportunities are
being pursued through regulatory initiatives in all of its jurisdictions which
have resulted in pilot transportation programs being offered in four of its five
service areas. Once fully implemented, these programs would reduce
Distribution's merchant function and provide customers with the opportunity for
reduced energy costs. Excess capacity costs and 


                                       26
<PAGE>   28

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

costs incurred by a utility associated with providing gas if the marketing
company cannot supply the gas that customers purchased, sometimes referred to as
the supplier of last resort, are two threshold issues that must be addressed as
these programs expand to all customers. The state commissions in Distribution's
five jurisdictions are at various stages in addressing these issues.
Distribution is currently recovering the costs resulting from the unbundling of
its services and believes that most such future costs and costs resulting from
being the supplier of last resort will be recovered. As set forth in its
regulatory settlement, as previously discussed, Columbia of Ohio will be at risk
for up to 11% of the transition capacity costs. In addition, Columbia of Ohio
has agreed to participate in discussions with interested parties regarding
issues related to being the supplier of last resort.

Columbia of Ohio's Customer CHOICE(R) pilot transportation program, which began
April 1, 1997, continues to add customers. There are now over 46,000 customers
participating, including 41,000 residential customers. Of 17 marketers approved
for participation, 13 are currently active in the program. The PUCO approved the
initial program for a one-year period. As discussed earlier, Columbia of Ohio
expects to expand the program to all of its 1.3 million customers beginning in
mid-1998.

In June 1997, Columbia Gas of Pennsylvania, Inc. (Columbia of Pennsylvania)
received approval from the Pennsylvania Public Utility Commission (PPUC) to
extend its pilot Customer CHOICE(R) program into Allegheny County, including the
city of Pittsburgh, beginning on November 1, 1997. There are nearly 26,000
customers and 9 marketers signed up to participate in the program. Columbia of
Pennsylvania has over 100,000 customers in Allegheny County who are eligible for
the program. Columbia of Pennsylvania's two-year pilot program began on November
1, 1996, in Washington County and there are over 11,000 out of a total of 37,000
customers and 9 marketers participating. As approved by the PPUC, the new
program will give marketers the option of using their own pipeline capacity,
rather than taking assignment of capacity held by Columbia of Pennsylvania.
Although the PPUC has not taken a final position on transition capacity costs,
such costs are currently being recovered through a surcharge mechanism.

In February 1998, Columbia Gas of Maryland, Inc. (Columbia of Maryland) reached
an agreement with the staff of the Maryland Public Service Commission and the
Maryland People's Counsel to settle a pending proceeding in which the People's
Counsel had sought an annual revenue reduction of $1.6 million, and Columbia of
Maryland had sought an annual revenue increase of $1.2 million. The settlement
agreement provides for an annual revenue increase of $200,000, which includes
the effect of a decrease in annual depreciation rates of approximately $534,000.
In June 1997, Columbia of Maryland entered into the second year of its pilot
transportation program for small commercial and industrial customers with 5
marketers and 500 customers participating. The second year of the residential
pilot program began in November 1997 and has 5 marketers and 2,500 customers
participating.

Columbia Gas of Virginia, Inc. (Columbia of Virginia), formerly Commonwealth Gas
Services, Inc., filed a rate case with the Virginia State Corporation Commission
(VSCC) in May 1997, requesting a $10.1 million increase in annual revenue.
Approximately $8.5 million of the requested increase is to recover normal
increases in the cost-of-service. Higher rates to recover these increased costs
went into effect on October 18, 1997, subject to refund. The remaining $1.6
million of the requested increase was based on recently passed legislation in
Virginia providing for performance-based ratemaking (PBR). The PBR rules allow
Columbia of Virginia to more timely recover the costs associated with its
capital expenditure program if certain service quality benchmarks are attained.
Also included were additional PBR rate increases of $1.9 million effective
October 18, 1998, and $900,000 effective October 18, 1999. On December 31, 1997,
Columbia of Virginia filed a motion to withdraw the PBR aspect of the case,
which was subsequently granted. This action was the result of a delay imposed by
the VSCC of the requested October 18, 1997 effective date for the initial $1.6
million PBR increase, pending the outcome of a hearing in mid-1998. The
withdrawal of the PBR converts the case to a traditional general rate case
proceeding.

On September 30, 1997, the VSCC approved Columbia of Virginia's proposed
two-year pilot transportation program for residential and small commercial
customers called Customer CHOICE(R) Program. The pilot program, which began
December 1, 1997, is open to approximately 27,000 customers in the Gainesville
market area of Northern Virginia. There are over 1,800 customers participating
in the program. These customers are served by 5 marketers out of a total of 8
approved to participate. Columbia of Virginia could expand the program and
eventually make it available to all of its 165,000 customers depending on the
results of the pilot program. Columbia of Virginia is the first company in
Virginia to file tariffs to support such a program.


                                       27
<PAGE>   29

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

Columbia of Virginia's 1995 rate case settlement provided for a separate
proceeding to consider capacity release and off-system sales proposals. A
hearing on these issues was held in September 1996, and the Hearing Examiner
issued a report in March 1997, recommending approval of Columbia of Virginia's
capacity release and off-system sales pilot incentive program. In October 1997,
the VSCC issued an order which permits Columbia of Virginia to retain a portion
of capacity release proceeds once a benchmark has been reached, but disallowed
any retention from off-system sales proceeds. Columbia of Virginia filed a
petition for rehearing and reconsideration. On November 4, 1997, the VSCC
granted partial reconsideration of its order by extending the capacity release
incentive pilot through the end of 1997, rather than ending it in October 1997,
as provided for by the original order. All other aspects of the petition for
rehearing were denied.

Columbia of Kentucky received permanent approval for the Weather Normalization
Adjustment (WNA) which had been on pilot status the previous three years. The
WNA alleviates the impact of unusual weather on customers' bills and Columbia of
Kentucky's revenues. Columbia of Maryland has a similar program in effect.

Voluntary Severance Program

In September 1997, Columbia of Pennsylvania and Columbia of Maryland announced a
voluntary severance program available to their 990 employees. The program was
the result of a review of the two companies' operations which identified some
opportunities to better position the companies in their evolving business
climate. As a result of this program, in the fourth quarter of 1997 Columbia of
Pennsylvania and Columbia of Maryland recorded a total of $4.3 million of costs
representing severance and benefit costs related to the voluntary severance of
79 management, professional, manual and administrative/technical employees that
elected to participate in the program. The majority of those participating left
the companies by the end of November 1997.

Capital Expenditure Program

In addition to maintaining and upgrading facilities to assure safe, reliable and
efficient operation, Distribution's 1997 capital expenditure program of
approximately $159 million (an increase of $11 million from 1996) included
expenditures of $64 million for extending service to new areas and $75 million
for replacement and betterment projects. The estimated 1998 capital expenditure
program amounts to approximately $162 million, including $65 million for new
business and development and $83 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 off-system sales and other incentive programs. Off-system sales
are sales or other transactions conducted outside of Distribution's traditional
market. For 1997, Distribution had off-system sales of 45.4 Bcf. This was a
significant increase of 34.6 Bcf from 1996 due to Columbia of Ohio's 1997 rate
settlement and indirectly to the mild weather in the first quarter of 1997 that
enabled Distribution to aggressively market its storage volumes in March 1997.
Columbia of Ohio, Columbia of Pennsylvania, Columbia of Maryland and Columbia of
Kentucky now have incentive programs in place that have been approved by their
respective regulatory commissions that provide for the sharing of the proceeds
from off-system sales with customers. For 1997, these programs resulted in
pre-tax income for Distribution of $26.1 million, an increase of $11.6 million
from 1996. Columbia of Ohio's 1996 rate settlement permits the retention of up
to $51 million from off-system sales over three years subject to an earnings
limitation.

Proceeds from releasing unused pipeline capacity totaled $19.5 million for 1997,
up $5.3 million from 1996. Distribution can retain a portion of the proceeds
that exceeds established capacity release incentive benchmarks. All other
proceeds are recorded as a reduction to gas costs and the benefit is passed
through to customers. In 1997, Columbia of Ohio, Columbia of Pennsylvania and
Columbia of Maryland were able to retain capacity release proceeds amounting to
$3.1 million. As residential and small commercial transportation programs
develop into widespread practice and marketers take assignment of the LDCs'
pipeline capacity contracts, earnings from these non-traditional services may
decline.

Environmental Matters

Distribution's primary environmental issues relate to 15 former manufactured gas
plant sites. Investigations or remedial activity are currently underway at seven
sites and additional site investigation may be required at some of the remaining
sites. To the extent Distribution's site investigations have been conducted,
remediation plans 


                                       28
<PAGE>   30

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

developed and any responsibility for remediation action established, the
appropriate liabilities have been recorded. Regulatory assets have been recorded
for a majority of these costs as rate recovery has been allowed or is
anticipated.

Throughput

For 1997, Distribution's throughput of 526.7 Bcf decreased 27.5 Bcf from 1996
due to warmer weather, an overall reduction in customer usage and a decrease in
industrial throughput of 7 Bcf due to the ten-month strike at a large industrial
customer. Higher demand for power generation and competitive natural gas prices
in 1997 contributed to a 10.1 Bcf increase in transportation volumes.

Distribution's 1996 throughput of 554.2 Bcf reflected an increase of 15.1 Bcf
over 1995 as residential and commercial sales rose 19 Bcf due to colder weather.
Transportation volumes decreased 7.1 Bcf reflecting reduced requirements for
power generation and increased pressure from competitive fuels due to higher
natural gas prices.

Net Revenues

Net revenues for 1997 of $898.1 million were down $8.6 million from 1996. The
decrease included the effect of 4% warmer weather that reduced net revenues by
approximately $23 million. This decrease was partially offset by an increase in
revenues for a 1997 regulatory settlement that Columbia of Ohio reached with
interested parties, together with income for certain gas management activities
that Columbia of Ohio retained under the terms of its 1996 rate settlement and
revenues generated by higher rates.

In 1996, net revenues of $906.7 million were up $85.2 million over 1995 due to
5% colder weather which contributed $26 million to the increase in net revenues,
while higher rates produced $21.2 million and Columbia of Ohio's retention of
revenues from certain gas management activities resulted in another $10.7
million. The remaining net revenue increase was attributable to increased
deliveries to higher margin transportation customers, customer growth and higher
revenue surcharges that were offset in expense.

Operating Income

Operating income for 1997 for Distribution of $224.2 million decreased by $1.8
million from 1996 as the decrease in net revenues was partially offset by a $6.8
million decrease in operating expenses. The decrease in operating expenses is
primarily the result of a reduced level of restructuring costs recorded in 1997
compared to 1996 and the implementation over the last two years of cost
conservation measures and operating efficiencies. Tempering these improvements
was costs related to a risk management program for Columbia of Ohio and Columbia
of Kentucky designed to mitigate potential adverse effects of certain future
business risks. Other taxes rose $11.4 million primarily due to increases in
gross receipts taxes and property taxes.

In 1996, operating income of $226 million increased $62.4 million as the
increase in net revenues was partially offset by an increase of $22.8 million in
operating expenses, primarily due to increased restructuring costs of $21.1
million.


                                       29
<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)                                 1997                          1996                       1995
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                                              <C>                           <C>                        <C>
NET REVENUES
 Sales revenues                                                  $2,153.1                      $2,007.9                   $1,677.8
 Less: Cost of gas sold                                           1,385.6                       1,206.4                      952.2
-----------------------------------------------------------------------------------------------------------------------------------
 Net Sales Revenues                                                 767.5                         801.5                      725.6
-----------------------------------------------------------------------------------------------------------------------------------
 Transportation revenues                                            143.2                         119.8                      105.3
 Less: Associated gas costs                                          12.6                          14.6                        9.4
-----------------------------------------------------------------------------------------------------------------------------------
 Net Transportation Revenues                                        130.6                         105.2                       95.9
-----------------------------------------------------------------------------------------------------------------------------------
Net Revenues                                                        898.1                         906.7                      821.5
-----------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
 Operation and maintenance                                          441.0                         463.0                      443.0
 Depreciation                                                        78.2                          74.4                       70.9
 Other taxes                                                        154.7                         143.3                      144.0
-----------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses                                            673.9                         680.7                      657.9
-----------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME                                                 $  224.2                      $  226.0                   $  163.6
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>





                                       30

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



                       DISTRIBUTION OPERATING HIGHLIGHTS
<TABLE>
<CAPTION>

<S>                                     <C>            <C>            <C>            <C>            <C>
                                             1997           1996           1995           1994           1993
--------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions)        159.5          148.4          151.8          151.4          117.8
--------------------------------------------------------------------------------------------------------------
THROUGHPUT (Bcf)
Sales
  Residential                               190.9          209.4          196.6          189.7          194.7
  Commercial                                 72.7           85.7           79.5           80.8           83.4
  Industrial and Other                        4.2           10.3            7.1            9.7           14.2
--------------------------------------------------------------------------------------------------------------
Total Sales                                 267.8          305.4          283.2          280.2          292.3
Transportation                              258.9          248.8          255.9          232.5          217.5
--------------------------------------------------------------------------------------------------------------
Total Throughput                            526.7          554.2          539.1          512.7          509.8
Off-System Sales                             45.4           10.8            7.5            0.3              -
--------------------------------------------------------------------------------------------------------------
Total Sold and Transported                  572.1          565.0          546.6          513.0          509.8
--------------------------------------------------------------------------------------------------------------
SOURCES OF GAS FOR THROUGHPUT (Bcf)
Sources of Gas Sold
  Spot market*                              295.0          298.7          210.4          235.3          142.3
  Producers                                  35.7           47.9           70.9           67.5           56.9
  Pipelines                                     -              -              -              -          118.4
  Storage withdrawals (injections)            4.0          (20.8)          23.6          (14.0)          (6.7)
  Company use and other                     (21.5)          (9.6)         (14.2)          (8.3)         (18.6)
--------------------------------------------------------------------------------------------------------------
Total Sources of Gas Sold                   313.2          316.2          290.7          280.5          292.3
Gas received for delivery to customers      258.9          248.8          255.9          232.5          217.5
--------------------------------------------------------------------------------------------------------------
Total Sources                               572.1          565.0          546.6          513.0          509.8
--------------------------------------------------------------------------------------------------------------
CUSTOMERS
Sales
  Residential                           1,769,647      1,815,269      1,794,800      1,764,968      1,737,609
  Commercial                              168,413        173,689        172,114        167,067        164,037
  Industrial and Other                      2,340          2,285          2,265          2,312          2,302
--------------------------------------------------------------------------------------------------------------
Total Sales Customers                   1,940,400      1,991,243      1,969,179      1,934,347      1,903,948
Transportation                             93,923         12,804          6,789          6,520          5,282
--------------------------------------------------------------------------------------------------------------
Total Customers                         2,034,323      2,004,047      1,975,968      1,940,867      1,909,230
--------------------------------------------------------------------------------------------------------------
DEGREE DAYS                                 5,736          5,975          5,692          5,530          5,677
--------------------------------------------------------------------------------------------------------------
</TABLE>

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




                                       31

<PAGE>   33

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


                      EXPLORATION AND PRODUCTION OPERATIONS


Acquisitions

On August 7, 1997, Columbia Resources acquired Alamco, a gas and oil production
company that operates in the Appalachian Basin, for $101 million. Under the
agreement, holders of Alamco received $15.75 per share of common stock. The
combined companies at the start of 1998 are producing approximately 125 million
cubic feet (Mmcf) of natural gas per day, making Columbia Resources one of the
largest natural gas and oil producers in the Appalachian Basin. This acquisition
provides contiguous assets that give Columbia Resources a major presence in
north-central West Virginia, southern Kentucky and northern Tennessee with
proved reserves of nearly 811 billion cubic feet of gas equivalent (Bcfe).

During the first quarter of 1998, Columbia Resources purchased producing assets
and undeveloped acreage in Ontario, Canada for approximately $3.6 million (U.S.
dollars). These assets consist of 26 producing wells and approximately 5,000
undeveloped acres.

Market Conditions

Although gas prices fluctuated considerably in 1997, gas prices were still
generally lower than 1996 prices. In January 1997, gas deliveries averaged
approximately $4.79 per Mcf in the Appalachian area but have steadily decreased
throughout the year, reflecting the impact of warmer weather and ample storage
inventory. Columbia Resources' natural gas prices averaged $2.63 per Mcf in
1997, compared with $2.84 per Mcf in 1996.

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

To lessen the impact of market price volatility, Columbia Resources has secured
an average price of $3.02 per Mcf for approximately 60% of its natural gas
production through October 1998 through a gas marketing affiliate. The gas
marketing affiliate in turn, as part of its normal course of business, hedged
these positions in the marketplace. Additional hedge transactions for 1998
production may be executed in the future to reduce Columbia Resources' remaining
exposure to market price fluctuations.

Gathering Facilities

On September 1, 1997, Columbia Transmission transferred to Columbia Resources
certain gathering facilities for $23 million. Approximately 70% of Columbia
Resources' production flows through this system.

Sale of Coal Assets

In December 1997, Columbia Resources sold its coal assets located in southern
West Virginia for $20.1 million that resulted in an improvement to income of
approximately $6 million after-tax. The sale involved underground reserves
containing more than 300 million tons of low-sulfur, steam quality coal
reserves.

Exploration and Drilling Program

Columbia Resources participated in the drilling of 131 gross wells of which 82%
were successful. In total, 1997 reserves increased 161.6 Bcfe, or 25%, over
1996. This increase included the acquisition of Alamco that contributed
approximately 95 Bcfe as well as the results of a series of successful
exploratory wells in New York. Total proven reserves as of December 31, 1997,
were estimated at 810.7 Bcfe. For 1998, Columbia Resources expects natural gas
production to reach approximately 51 Bcf, an increase of 47% from 1997.

Capital Expenditure Program

In order to meet its drilling objectives, Columbia Resources' capital
expenditure program for 1998 is approximately $86 million. This investment will
support development of traditional Appalachian prospects as well as continue
definition in deeper horizons, such as upstate New York. Included in the $136
million program for 1997 was $101 million for the acquisition of Alamco. Not
reflected in the 1997 program was an additional $23 million for the purchase of
gathering facilities from Columbia Transmission. Columbia Resources continues to
pursue opportunities to expand its operations which may include additional
capital expenditures for acquisitions that are not reflected in the current
estimate for 1998, which primarily reflects drilling efforts.


                                       32
<PAGE>   34

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

Production

Gas production in 1997 increased 3% to 34.7 Bcf over 1996 due to the acquisition
of Alamco as well as production shut-ins during 1996 resulting from facility
problems at Columbia Transmission's Kanawha Extraction Plant. From 1995 to 1996,
gas production volumes decreased 49% to 33.6 Bcf reflecting the sale of
Columbia's southwest gas and oil subsidiary, Columbia Gas Development
Corporation (Columbia Development). After adjusting for this sale, gas
production was essentially unchanged.

Oil and liquids produced was down 25% from 1996 to 210,000 barrels largely due
to Columbia Resources' sale of a production field in December 1996. In 1996,
production was down 2.6 million barrels to 281,000 barrels compared to 1995 due
to the sale of Columbia Development.

Operating Revenues

Operating revenues for 1997 were $113.3 million, an increase of $8.8 million
from 1996, primarily for a reclassification in the recording of gathering
activities. The recovery of gathering costs is now reflected in revenues with
costs associated with gathering activities included as an operating expense;
therefore, the change in reporting has no impact on operating income.
Previously, gathering activities were shown net of associated expenses. After
adjusting for gathering revenues, total operating revenues increased $1.9
million primarily due to a $4.1 million first quarter 1997 improvement related
to cash received from a contract buyout by a cogeneration facility. In addition,
volumes increased 3% over the prior period adding $3.2 million to operating
revenues. These improvements were offset by the impact of lower prices and
reduced oil and liquids production. The weaker natural gas prices reflected the
impact of warmer weather and ample storage inventory. Columbia Resources'
average gas sales price for 1997 was $2.63 per Mcf, down more than 7% from last
year. Operating revenues of $104.5 million in 1996 were down $76.1 million from
1995 due to the sale of Columbia Development at year-end 1995.

Operating Income

Operating income of $30.9 million for 1997 reflected a small improvement of
$900,000 from the prior year. The increase in operating revenues was largely
offset by higher operation and maintenance expense due primarily to additional
costs associated with the acquisition of Alamco. From 1995 to 1996, operating
income increased by $26.3 million to $30 million primarily reflecting higher
average gas prices as well as lower operating expenses resulting from the sale
of Columbia Development and reengineering initiatives.


                                       33
<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)                                          1997                     1996                   1995
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                                                         <C>                      <C>                    <C>
OPERATING REVENUES
 Gas                                                                        $109.5                   $ 99.1                 $134.4
 Oil and liquids                                                               3.8                      5.4                   46.2
-----------------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues                                                     113.3                    104.5                  180.6
-----------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
 Operation and maintenance                                                    45.7                     37.0                   79.6
 Depreciation and depletion                                                   27.6                     28.8                   86.9
 Other taxes                                                                   9.1                      8.7                   10.4
-----------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses                                                      82.4                     74.5                  176.9
-----------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME                                                            $ 30.9                   $ 30.0                 $  3.7
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

                EXPLORATION AND PRODUCTION OPERATING HIGHLIGHTS*

<TABLE>
<CAPTION>
                                                  1997               1996             1995                1994               1993
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                              <C>                <C>              <C>                <C>                <C>
CAPITAL EXPENDITURES ($ in millions)             158.7               12.1             86.8               101.6               95.1
-----------------------------------------------------------------------------------------------------------------------------------
PROVED RESERVES
Gas (Bcf)                                        800.5              644.5             599.5               683.8              697.0
Oil and Liquids (000 barrels)                    1,700                774             1,651              12,255             12,792
-----------------------------------------------------------------------------------------------------------------------------------
PRODUCTION
Gas (Bcf)                                         34.7               33.6              65.4                66.7               71.5
Oil and Liquids (000 barrels)                      210                281             2,849               3,611              3,603
-----------------------------------------------------------------------------------------------------------------------------------
AVERAGE PRICES
Gas ($ per Mcf)**                                 2.63               2.84              1.96                2.18               2.28
Oil and Liquids ($ per barrel)                   17.99              19.07             16.17               15.09              16.17
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

* Years 1993 through 1995 include operating results from Columbia Development,
  which was sold effective December 31, 1995.

**Includes the effect of hedging activities.



                                       34
<PAGE>   36

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


               MARKETING, PROPANE AND POWER GENERATION OPERATIONS

During 1997, the Marketing, Propane and Power Generation segment was involved in
several transactions designed to help achieve Columbia's goal to increase its
nonregulated operations' contribution to consolidated results. Columbia Energy
Services acquired PennUnion, an energy-marketing subsidiary of Pennzoil and
signed an agreement to purchase and market Kerr-McGee Corporation's (Kerr-McGee)
offshore natural gas production. In addition, Commonwealth Propane, Inc.
(Commonwealth Propane) purchased the assets of Supertane Gas Corporation
(Supertane). Each of these transactions is discussed more fully below.

Energy Marketing Operations

As utility regulations provide for a more open and competitive environment, LDCs
are beginning to unbundle services, thereby creating an opportunity for Columbia
Energy Services and other marketing companies to provide natural gas and other
services to retail customers. In this new environment, LDCs will substantially
reduce their merchant function and primarily become a transporter of natural
gas. Marketing companies are positioned to provide cost-effective gas supplies
and will assume this merchant role. The LDC customers may benefit from reduced
utility costs. Pilot programs underway in Ohio and other states have
demonstrated that there is substantial demand for these services and that this
market has significant potential for growth.

Columbia Energy Services provides gas and electricity 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 residential customers.

On June 30, 1997, Columbia Energy Services purchased PennUnion for approximately
$14.75 million, subject to certain working capital and other adjustments.
Including the PennUnion operations, Columbia Energy Services' trading volumes
are nearly 4 Bcf per day. A portion of Columbia Energy Services' marketing
volumes is represented by a contract committing Columbia Energy Services to
purchase most of Pennzoil's U.S. natural gas production of approximately 585
Mmcf per day at certain index prices. This contract is for a four-year period.

Effective May 1, 1997, Columbia Energy Services began purchasing and marketing
Kerr-McGee's offshore natural gas production of approximately 250 Mmcf per day
totaling 90 Bcf a year. The marketing alliance will continue for three years.
Columbia Energy Services will manage all of Kerr-McGee's U.S. natural gas
marketing activities including scheduling, nominating and balancing pipeline
transportation as well as providing financial risk management services.

Columbia Energy Services has taken several other initiatives to become a full
service provider of energy and energy-related services. During the fourth
quarter of 1997, Columbia Energy Services began marketing electricity through
its recently formed wholly-owned subsidiary, Columbia Power Marketing
Corporation. A ten-year natural gas supply contract between Columbia Energy
Services and a municipal gas authority was also signed in December 1997.
Effective January 1, 1998, Columbia Energy Services will sell the municipal gas
authority approximately 12 Mmcf of natural gas per day. As part of the
agreement, in December 1997, the municipal gas authority made an advance payment
of $71.6 million for such future deliveries.

In October 1997, Columbia Energy Services and Honeywell Inc. (Honeywell) formed
an alliance to sell a targeted set of products and services in a seven-state
region for use in homes, commercial buildings and industrial facilities.
Columbia Energy Services and Honeywell began offering these products and
services in the fourth quarter of 1997, which include indoor air quality
solutions, ventilating and air conditioning systems, energy strategy consulting
as well as control automation solutions to reduce energy consumption.

Columbia Energy Services needs to strengthen its infrastructure to accommodate
the significant increase in the volume of business and to improve its business
practices. Such needed improvements are of the type associated with "start-up"
enterprises, and include the hiring of additional skilled personnel, the
development of new policies and procedures for trading, risk management, credit,
contract administration and documentation, as well as new computer systems for
accounting, marketing management and customer service. During 1997, $4 million
was spent on these activities, and an additional $29 million is expected to be
spent in 1998, of which approximately $27 million will be capital expenditures.
It is anticipated, however, that continued management attention to Columbia


                                       35
<PAGE>   37

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

Energy Services' infrastructure and continued expenditures and improvements will
be required as the company builds and expands its business.

Propane

During the first quarter of 1997, Commonwealth Propane purchased the assets of
Supertane of Ranson, West Virginia. This acquisition added 7,700 customers and
approximately 3.9 million gallons annually. In October 1997, Commonwealth
Propane was merged into Columbia Propane Corporation (Columbia Propane) to
increase administrative and operating efficiencies. Columbia Propane serves
approximately 97,000 customers in parts of 10 eastern states and the District of
Columbia. Total propane sales for 1997 were 70.9 million gallons, a decrease of
5 million gallons from 1996, resulting from significantly warmer weather in the
first quarter of 1997 and lower spot market sales activity.

In February 1998, Columbia Propane purchased certain assets of Central Jersey
Propane, Inc. (Ace Gas) located in New Jersey. Ace Gas sells approximately 2.2
million gallons of propane annually to 3,600 customers.

Power Generation

Columbia is part owner in three cogeneration projects through its subsidiary,
Columbia Electric Corporation (Columbia Electric), formerly TriStar Ventures
Corporation. These facilities produce both electricity and useful thermal energy
fueled principally by natural gas. Columbia Electric holds various interests in
these facilities that have a total capacity of approximately 250 megawatts.
Columbia Electric'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 contracts.

On January 29, 1998, Columbia Electric and Westcoast Energy Inc. signed a joint
ownership agreement to develop three natural gas-fired electricity generating
plants by 2001. In total, the three plants will provide approximately 1000
megawatts of electricity using approximately 160 Mmcf per day of natural gas.
Total development costs are estimated at $600 million to $700 million. The exact
locations of the plants have yet to be determined.

Commodity Hedging

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

Columbia Energy Services uses these financial transactions to provide acceptable
margins on the purchase and resale of natural gas in future months. When
Columbia Energy Services makes a sale for future delivery without having natural
gas committed to that sale, it purchases derivative instruments to reduce the
risk of increasing prices prior to purchasing the natural gas to fulfill the
sales obligation. Conversely, Columbia Energy Services may use derivative
instruments to mitigate price volatility on future sales if it has contracted
for natural gas supplies before obtaining a firm sales commitment. In late 1997,
Columbia Energy Services began trading of electric power.

Columbia Propane purchases propane and places it in storage for future sale.
Columbia Propane sells commodity futures on a portion of its inventory at the
time of purchase to hedge against decreasing prices.

Net Revenues

Net revenues for 1997 increased $9.9 million over last year to $66.5 million.
Columbia Energy Services' volumes more than tripled the 1996 level to 888.4 Bcf,
reflecting the significant growth of Columbia Energy Services' operations
including the effect of the PennUnion acquisition and the agreement with
Kerr-McGee. Much of the growth came from increased lower-margin wholesale sales
that was necessary to expand Columbia Energy Services' base for future retail
growth. The impact of higher sales volumes was nearly offset by a decrease in
average margins that resulted in a total net gas marketing revenue increase of
$4.3 million. Net revenues for Columbia Propane increased $2.3 million due to
11% higher margins, which were partially offset by a 7% decrease in volumes
resulting from the warmer than normal weather experienced in the first quarter
of 1997 and lower spot market sales activity. Columbia Electric recorded $2.6
million in revenues for assuming Binghamton Partnership's gas transportation
contract with Columbia Transmission.


                                       36
<PAGE>   38

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

Net revenues for 1996 increased $9.6 million over 1995 due to the favorable
effect of colder weather which increased volumes for both Columbia Energy
Services and Columbia Propane. Net revenues in 1996 from power generation
activities were essentially unchanged from 1995.

Operating Income (Loss)

An operating loss of $2.9 million was recorded in 1997 compared to a gain of
$12.5 million in the prior period. The increase in net revenues was more than
offset by higher operating costs associated with expanding the gas marketing
operations and building its infrastructure. As mentioned previously, these costs
include, among other things, implementing operational improvements and adding
additional staff. Operation and maintenance expense for Columbia Propane also
increased over the prior period due to increased staffing levels resulting from
its purchase of the assets of Supertane. In addition, start-up costs for new
services led to higher operating costs.

In 1996, operating income increased a modest $300,000 over 1995 to $12.5
million. The increase in Columbia Energy Services' net revenues was partially
offset by higher operating expenses due largely to the start-up costs for new
services.


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

<TABLE>
<CAPTION>

Year Ended December 31 (in millions)               1997         1996           1995
-------------------------------------------------------------------------------------
<S>                                          <C>            <C>            <C>
NET REVENUES                                 
  Gas marketing revenues                     $  2,186.8     $  728.0       $  237.9
  Less: Products Purchased                      2,166.0        711.5          230.8
-------------------------------------------------------------------------------------
  Net Gas Marketing Revenues                       20.8         16.5            7.1
-------------------------------------------------------------------------------------
  Propane revenues                                 77.9         80.7           65.1
  Less: Products purchased                         43.2         48.3           35.5
-------------------------------------------------------------------------------------
  Net Propane Revenues                             34.7         32.4           29.6
-------------------------------------------------------------------------------------
  Other revenues                                   11.0          7.7           10.3
-------------------------------------------------------------------------------------
Net Revenues                                       66.5         56.6           47.0
-------------------------------------------------------------------------------------
OPERATING EXPENSES
  Operation and maintenance                        61.2         38.8           29.7
  Depreciation                                      5.2          3.1            2.6
  Other taxes                                       3.0          2.2            2.5
-------------------------------------------------------------------------------------
Total Operating Expenses                           69.4         44.1           34.8
-------------------------------------------------------------------------------------
OPERATING INCOME (LOSS)                      $     (2.9)    $   12.5       $   12.2
-------------------------------------------------------------------------------------
</TABLE>



                                       37
<PAGE>   39

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



          MARKETING, PROPANE AND POWER GENERATION OPERATING HIGHLIGHTS
<TABLE>
<CAPTION>

                                             1997           1996           1995          1994            1993
--------------------------------------------------------------------------------------------------------------
<S>                                     <C>            <C>            <C>            <C>            <C>
CAPITAL EXPENDITURES ($ in millions)         15.0            6.3            6.6           4.7             9.7
--------------------------------------------------------------------------------------------------------------
PROPANE
Gallons sold (millions)                      70.9           75.9           68.9          68.5            58.1
Customers                                  96,954         79,650         74,308        68,218          67,895
--------------------------------------------------------------------------------------------------------------
MARKETING SALES (Bcf)                       888.4          259.6          131.6         111.2            81.5
--------------------------------------------------------------------------------------------------------------
</TABLE>
                  





                               BANKRUPTCY MATTERS

On November 28, 1995, Columbia and its wholly-owned subsidiary, 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. 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. Certain residual
unresolved bankruptcy-related matters are still within the jurisdiction of the
Bankruptcy Court.

Columbia Transmission's approved plan of reorganization (Plan) was 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 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 since the actual distribution
percentage for all producer claims, which would not be less than 68.875% or
greater than 72.5%, cannot be determined until the total amount of producer
claims is essentially established, 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 until the total has been
determined. An interim distribution could be made if Columbia Transmission
determines at any time that the holdback amount exceeds parameters stated in its
Plan.

Columbia believes adequate reserves have been established for resolution of the
remaining producer claims.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information required by this item is in Item 7 on page 19.


                                       38
<PAGE>   40


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index                                                                       Page
--------------------------------------------------------------------------------
Report of Independent Public Accountants .................................   40
Statements of Consolidated Income ........................................   41
Consolidated Balance Sheets ..............................................   42
Statements of Consolidated Cash Flows ....................................   44
Statements of Consolidated Common Stock Equity ...........................   45
Notes of Consolidated Financial Statements ...............................   46
Schedule II - Valuation and Qualifying Accounts ..........................   69
--------------------------------------------------------------------------------


                                       39
<PAGE>   41

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS


To the Shareholders of Columbia Energy Group:


We have audited the accompanying consolidated balance sheets of Columbia Energy
Group (a Delaware corporation, the "Corporation") and subsidiaries as of
December 31, 1997 and 1996, 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, 1997. 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, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.

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 23, 1998


                                       40
<PAGE>   42
ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

                       STATEMENTS OF CONSOLIDATED INCOME
                     Columbia Energy Group and Subsidiaries
<TABLE>
<CAPTION>
                                                              
Year Ended December 31 (in millions, except per share amounts)         1997           1996           1995*
----------------------------------------------------------------------------------------------------------
<S>                                                              <C>            <C>            <C>         
OPERATING REVENUES                                                                                        
 Gas sales                                                       $  4,286.7     $  2,679.4     $  1,929.0
 Transportation                                                       531.5          491.3          487.7
 Other                                                                235.4          183.3          218.5
----------------------------------------------------------------------------------------------------------
Total Operating Revenues                                            5,053.6        3,354.0        2,635.2
----------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
 Products purchased                                                 3,138.1        1,481.1          820.6
 Operation                                                            862.1          854.5          826.7
 Maintenance                                                          100.2          111.4          116.6
 Depreciation and depletion                                           221.3          215.2          270.0
 Other taxes                                                          222.5          213.6          211.1
----------------------------------------------------------------------------------------------------------
Total Operating Expenses                                            4,544.2        2,875.8        2,245.0
----------------------------------------------------------------------------------------------------------
OPERATING INCOME                                                      509.4          478.2          390.2
----------------------------------------------------------------------------------------------------------
OTHER INCOME (DEDUCTIONS)
 Interest income and other, net (Note 14)                              40.4           26.1          (58.2)
 Interest expense and related charges** (Note 15)                    (157.6)        (166.8)        (988.4)
 Reorganization items, net (Note 2)                                       -              -           13.4
----------------------------------------------------------------------------------------------------------
Total Other Income (Deductions)                                      (117.2)        (140.7)      (1,033.2)
----------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY ITEM              392.2          337.5         (643.0)
Income taxes (Note 7)                                                 118.9          115.9         (210.7)
----------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM                               273.3          221.6         (432.3)
  Extraordinary item (Note 1)                                             -              -           71.6
----------------------------------------------------------------------------------------------------------
NET INCOME (LOSS)                                                  $  273.3       $  221.6      $  (360.7)
==========================================================================================================
EARNINGS (LOSS) PER SHARE OF COMMON STOCK
  (based on average shares outstanding)
    Before extraordinary item                                      $   4.93       $    4.12     $   (8.57)
    Extraordinary item                                                  -               -            1.42
----------------------------------------------------------------------------------------------------------
Earnings (Loss) Per Share of Common Stock                          $   4.93       $    4.12     $   (7.15)
----------------------------------------------------------------------------------------------------------
DIVIDENDS PAID PER SHARE OF COMMON STOCK                           $   0.90       $    0.60     $        -
----------------------------------------------------------------------------------------------------------
AVERAGE COMMON SHARES OUTSTANDING (thousands)                        55,405          53,792         50,477
----------------------------------------------------------------------------------------------------------
</TABLE>

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

**   Due to the bankruptcy filings, interest expenses of $982.9 million,
     including the write-off of unamortized discounts on debentures, was
     recorded in the fourth quarter of 1995. (See Note 2 of Notes to
     Consolidated Financial Statements.)

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







                                       41
<PAGE>   43
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

                          CONSOLIDATED BALANCE SHEETS
                     Columbia Energy Group and Subsidiaries

<TABLE>
<CAPTION>
ASSETS as of December 31 (in millions)                        1997       1996
--------------------------------------------------------------------------------
<S>                                                         <C>        <C>
PROPERTY, PLANT AND EQUIPMENT
  Gas utility and other plant, at original cost             $ 7,368.9  $ 6,994.4
  Accumulated depreciation                                   (3,481.5)  (3,344.5)
--------------------------------------------------------------------------------
  Net Gas Utility and Other Plant                             3,887.4    3,649.9
--------------------------------------------------------------------------------
  Gas and oil producing properties, full cost method            660.2      502.8
  Accumulated depletion                                        (196.0)    (146.4)
--------------------------------------------------------------------------------
  Net Gas and Oil Producing Properties                          464.2      356.4
--------------------------------------------------------------------------------
Net Property, Plant and Equipment                             4,351.6    4,006.3
--------------------------------------------------------------------------------
INVESTMENTS AND OTHER ASSETS
  Accounts receivable - noncurrent                                1.6        6.3
  Unconsolidated affiliates                                      74.1       69.0
  Assets held for sale                                            1.5       12.1
  Other                                                           8.0       15.9
--------------------------------------------------------------------------------
Total Investments and Other Assets                               85.2      103.3
--------------------------------------------------------------------------------
CURRENT ASSETS
  Cash and temporary cash investments                            28.7       49.8
  Accounts receivable
   Customer (less allowance for doubtful accounts
    of $18.7 and $16.2, respectively)                           815.8      562.2
   Other                                                         52.7       35.4
  Gas inventory                                                 226.8      237.8
  Other inventories - at average cost                            35.6       45.1
  Prepayments                                                   107.7       73.8
  Regulatory assets                                              64.6       63.4
  Underrecovered gas costs                                       41.4      104.7
  Prepaid property tax                                           80.8       81.1
  Exchange gas receivable                                       189.0      114.6
  Other                                                          64.6       68.0
--------------------------------------------------------------------------------
Total Current Assets                                          1,707.7    1,435.9
--------------------------------------------------------------------------------
REGULATORY ASSETS                                               400.9      410.1
DEFERRED CHARGES                                                 66.9       49.0
--------------------------------------------------------------------------------
TOTAL ASSETS                                                 $6,612.3   $6,004.6
--------------------------------------------------------------------------------
</TABLE>

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

                                       42
<PAGE>   44
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)


<TABLE>
<CAPTION>
CAPITALIZATION AND LIABILITIES as of December 31 (in millions)             1997            1996
--------------------------------------------------------------------------------------------------
<S>                                                                       <C>           <C>
COMMON STOCK EQUITY
  Common stock, par value $10 per share - issued
   55,495,460 and 55,263,659 shares, respectively                          $   554.9     $   552.6
  Additional paid in capital                                                   754.2         743.2
  Retained earnings                                                            482.7         259.3
  Unearned employee compensation                                                (1.1)         (1.5)
--------------------------------------------------------------------------------------------------
Total Common Stock Equity                                                    1,790.7       1,553.6
LONG-TERM DEBT (Note 10)                                                     2,003.5       2,003.8
--------------------------------------------------------------------------------------------------
Total Capitalization                                                         3,794.2       3,557.4
--------------------------------------------------------------------------------------------------
CURRENT LIABILITIES
  Short-term debt (Note 11)                                                    328.1         250.0
  Accounts and drafts payable                                                  536.7         348.6
  Accrued taxes                                                                140.9         142.6
  Accrued interest                                                              29.4          14.8
  Estimated rate refunds                                                        68.4         114.0
  Estimated supplier obligations                                                73.9         115.1
  Overrecovered gas costs                                                       84.6            --
  Transportation and exchange gas payable                                       89.2          95.4
  Other                                                                        367.0         371.1
--------------------------------------------------------------------------------------------------
Total Current Liabilities                                                    1,718.2       1,451.6
--------------------------------------------------------------------------------------------------
OTHER LIABILITIES AND DEFERRED CREDITS
  Deferred income taxes - noncurrent                                           618.4         557.7
  Investment tax credits                                                        35.6          37.1
  Postretirement benefits other than pensions                                  148.8         172.3
  Regulatory liabilities                                                        41.3          44.5
  Other                                                                        255.8         184.0
--------------------------------------------------------------------------------------------------
Total Other Liabilities and Deferred Credits                                 1,099.9         995.6
--------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Notes 2, 3 and 13)                                 --            --
--------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES                                        $6,612.3      $6,004.6
--------------------------------------------------------------------------------------------------
</TABLE>


                                       43
<PAGE>   45
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

                      STATEMENTS OF CONSOLIDATED CASH FLOWS
                     Columbia Energy Group and Subsidiaries

<TABLE>
<CAPTION>
Year Ended December 31 (in millions)                          1997       1996     1995*
-----------------------------------------------------------------------------------------
<S>                                                         <C>        <C>      <C>
OPERATING ACTIVITIES
  Net income (loss)                                         $ 273.3    $221.6   $  (360.7)
  Adjustments for items not requiring (providing) cash:
   Depreciation and depletion                                 221.3     215.2       270.0
   Deferred income taxes                                       29.3      78.1        66.1
   Earnings from equity investment, net of distributions        2.4       9.2       (15.5)
   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**                                                32.2      (5.7)      (75.2)
  Changes in components of working capital:
   Accounts receivable                                       (199.2)    (64.3)       99.7
   Income tax refunds                                            --     271.5          --
   Gas inventory                                               11.0     (65.6)       58.0
   Prepayments                                                (33.9)    (16.3)       12.3
   Accounts payable                                           186.8     160.8        38.3
   Accrued taxes                                              (30.4)    (85.5)     (314.9)
   Accrued interest                                            (1.2)    (71.5)      (56.5)
   Estimated rate refunds                                     (45.6)     17.8       (56.6)
   Estimated supplier obligations                             (41.2)    (63.2)      (44.0)
   Under/Overrecovered gas costs                              147.9    (146.3)      (18.0)
   Exchange gas receivable/payable                            (89.5)     46.9        17.4
   Other working capital                                        5.0     (25.7)       35.5
-----------------------------------------------------------------------------------------
Net Cash From Operations                                      468.2     477.0      (804.1)
-----------------------------------------------------------------------------------------
INVESTMENT ACTIVITIES
  Capital expenditures                                       (420.5)   (316.4)     (411.0)
  Proceeds received on the sale of
   Columbia Gas Development Corp.                                --     187.8          --
  Purchase of Alamco, Inc.                                    (99.4)       --          --
  Sale of partnership interest                                   --       2.7        10.9 
  Other investments - net                                      (9.1)       --        21.9
-----------------------------------------------------------------------------------------
Net Investment Activities                                    (529.0)   (125.9)     (378.2)
-----------------------------------------------------------------------------------------
FINANCING ACTIVITIES
  Retirement of prepetition debt obligations                     --        --      (637.3)
  Retirement of preferred stock                                  --    (400.0)         --
  Dividends paid                                              (49.9)    (32.1)         --
  Issuance of common stock                                     11.7     250.8         1.8
  Issuance (repayment) of short-term debt                      77.1     (88.9)      338.9
  Other financing activities                                    0.8     (39.1)        5.1
-----------------------------------------------------------------------------------------
Net Financing Activities                                       39.7    (309.3)     (291.5)
-----------------------------------------------------------------------------------------
Increase (Decrease) in cash and temporary cash investments    (21.1)     41.8    (1,473.8)
Cash and temporary cash investments at beginning of year       49.8       8.0     1,481.8
-----------------------------------------------------------------------------------------
CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR          $  28.7   $  49.8   $     8.0
-----------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
  Cash paid for interest                                    $ 145.4   $ 150.9   $   284.9
  Cash paid for income taxes (net of refunds)               $  90.7   $ (93.4)  $    42.3
-----------------------------------------------------------------------------------------
</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) million in 1995.

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

                                       44
<PAGE>   46
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

                 STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY

                     Columbia Energy Group and Subsidiaries

<TABLE>
<CAPTION>
                                         Common Stock*
                           -----------------------------------------
                                   Shares                               Additional                        Unearned
(in millions, except          Outstanding         Par       Treasury       Paid In       Retained         Employee           
for share amounts)                   (000)       Value        Stock        Capital       Earnings     Compensation          Total
-----------------------------------------------------------------------------------------------------------------------------------
<S>                           <C>               <C>         <C>         <C>              <C>          <C>                 <C>
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
Net income                                                                                  273.3                            273.3
Cash dividends:
 Common stock                                                                               (49.9)                           (49.9)
Common stock issued:
 Long-term incentive plan             232          2.3                        11.0                              0.4           13.7
-----------------------------------------------------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1997       55,496       $554.9        $    -        $754.2        $ 482.7            $ (1.1)      $1,790.7
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

* 100 million shares authorized at December 31, 1997, 1996, 1995 and 1994 - $10
  par value.

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



                                       45

<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 Energy Group (Columbia) and all subsidiaries. All
intercompany accounts and transactions have been eliminated. Certain
reclassifications have been made to the 1996 and 1995 financial statements to
conform to the 1997 presentation.

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

C. EARNINGS PER SHARE. In February 1997, the Financial Accounting Standards
Board issued Statement of Financial Accounting Standards No. 128, "Earnings per
Share" (SFAS No. 128). This statement supersedes APB Opinion No. 15, "Earnings
per Share" and simplifies the computation of earnings per share (EPS). Primary
EPS is replaced with a presentation of Basic EPS. Basic EPS includes no dilution
and is computed by dividing income available to common stockholders by the
weighted-average number of common shares outstanding for the period. In
addition, Fully Diluted EPS is replaced with Diluted EPS. Diluted EPS reflects
the potential dilution if certain securities are converted into common stock.
This statement requires dual presentation of Basic and Diluted EPS by entities
with complex capital structures and also requires restatement of all
prior-period EPS data presented. SFAS No. 128 is effective for financial
statements for both interim and annual periods after December 15, 1997.

Under the requirements of SFAS No. 128, Columbia's  Diluted EPS are as follows:

<TABLE>
<CAPTION>
Diluted EPS Computation                               1997      1996        1995
----------------------------------------------------------------------------------
<S>                                                 <C>       <C>         <C>    
Net Income (Loss) ($ in millions)                     273.3     221.6       (360.7)
----------------------------------------------------------------------------------
Denominator (thousands)
   Average Common shares outstanding                 55,405    53,792       50,477
   Dilutive potential common shares - options           329       159           --(a)
----------------------------------------------------------------------------------
   Diluted Average Common Shares                     55,734    53,951       50,477
----------------------------------------------------------------------------------
DILUTED EARNINGS (LOSS) PER SHARE OF COMMON STOCK   $  4.90   $  4.11     $  (7.15)
----------------------------------------------------------------------------------
</TABLE>

(a)  The addition of 57 dilutive potential common shares would be antidilutive
     in the 1995 computation of Diluted EPS, and therefore, are not included.

D. 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. Columbia's transmission subsidiaries reapplied the provisions of SFAS
No. 71 during 1995, concurrent with the emergence from Chapter 11 protection. As
a result of reapplying SFAS No. 71, an extraordinary gain of $71.6 million was
recorded in 1995. 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.


                                       46
<PAGE>   48

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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)                           1997      1996      1997      1996
--------------------------------------------------------------------------------------------
<S>                                                      <C>       <C>       <C>       <C>
ASSETS
 Environmental costs                                     125.8     123.6       7.4       7.1
 Postemployment and postretirement benefits               64.6      69.4     121.8     129.9
 Percent of income plan receivables                       --        --        22.6      17.9
 Retirement income plan costs                             21.7      21.4      19.2      20.2
 Regulatory effects of accounting for income taxes        --        --        50.8      49.0
 Post in-service carrying charges                         --        --        18.3      18.9
 Underrecovered gas costs                                 --        --        41.4     104.7
 Other                                                     7.4       9.9       5.9       6.3
--------------------------------------------------------------------------------------------
TOTAL REGULATORY ASSETS                                  219.5     224.3     287.4     354.0
--------------------------------------------------------------------------------------------
LIABILITIES
 Rate refunds and reserves                                55.9      95.5      12.5      18.4
 Overrecovered gas costs                                  --        --        84.6      --
 Regulatory effects of accounting for income taxes        19.5      21.5      24.1      25.2
 Other                                                     7.5       6.8      --        --
--------------------------------------------------------------------------------------------
TOTAL REGULATORY LIABILITIES                              82.9     123.8     121.2      43.6
--------------------------------------------------------------------------------------------
</TABLE>

E. 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
1997 before-tax rates for AFUDC and IDC were 7.09% and 7.05%, respectively. The
1996 and 1995 before-tax rates for AFUDC were 6.15% and 8%, respectively, and
for IDC were 6.9% and 9.6%, 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% in 1997, 2.5% in 1996 and 2.6% in 1995. The average annual depreciation
rate for the distribution subsidiaries' property was 3.2% in 1997, 3.2% in 1996
and 3.1% in 1995.


F. GAS AND OIL PRODUCING PROPERTIES. Columbia's subsidiary engaged in exploring
for and developing gas and oil reserves follows 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 the subsidiary 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 would 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, which increased income.


                                       47
<PAGE>   49

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

G. COMMODITY HEDGING. In accordance with Statement of Financial Accounting
Standards No. 80, "Accounting for Futures Contracts," a futures contract
qualifies as a hedge if the commodity to be hedged is exposed to price risk and
the futures contract reduces that exposure and is designated as a hedge.
Subsidiaries in Columbia's production, marketing and propane operations engage
in commodity hedging activities to help minimize the risk of market fluctuations
associated with the price of natural gas 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. These positions are hedged in the marketplace through a gas
marketing affiliate.

Columbia's marketing and propane operations utilize futures contracts and basis
swaps to help assure adequate margins on the purchase and resale of natural gas
as well as protecting the value and margins of its propane inventories.

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 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 futures, options
and swaps are included in revenues or products purchased as appropriate,
concurrent with the associated physical transaction. Realized gains and losses
from the settlement of propane futures contracts are included in products
purchased. The cash flows from commodity hedging are included in operating
activities in the consolidated statement of cash flows.

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
significantly reduced as a result of these hedging contracts which are primarily
with major investment grade financial institutions or their affiliates.

H. 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, 1997, over the carrying value is approximately $25
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.

I. 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.

J. 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 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.

K. 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.


                                       48
<PAGE>   50

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

L. 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.

M. 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.

N. 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.

O. 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. Restricted stock awards are recorded as deferred compensation in the
consolidated balance sheet at the date of grant. Compensation expense related to
restricted stock awards is recognized ratably over the vesting period.
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 minimis, 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, 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. 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. Certain residual unresolved bankruptcy-related
matters are still within the jurisdiction of the Bankruptcy Court.

Columbia Transmission's approved plan of reorganization (Plan) was 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 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 since the actual distribution
percentage for all producer claims, which would not be less than 68.875% or
greater than 72.5%, can not be determined until the total amount of producer
claims is essentially established, 5% of the maximum amount (based on 72.5%
payout) to be distributed to producer claimants for allowed claims and to
Columbia for unsecured debt will be withheld until the total has been
determined. An interim distribution could be 


                                       49
<PAGE>   51

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

made if Columbia Transmission determines at any time that the holdback amount
exceeds the parameters stated in the Plan.

Columbia believes adequate reserves have been established for resolution of the
remaining producer claims and the payment of any amounts ultimately due to
producers with respect to the 5% holdback.

B. REORGANIZATION ITEMS. During the bankruptcy period, Columbia and Columbia
Transmission 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.

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

<TABLE>
<CAPTION>
($ in millions)                                      1997      1996        1995
--------------------------------------------------------------------------------
<S>                                                  <C>       <C>        <C>
Interest income on accumulated cash                    --        --        93.5
Professional fees and related expenses                 --        --       (28.2)
Other reorganization items, net                        --        --       (51.9)
--------------------------------------------------------------------------------
REORGANIZATION ITEMS, NET                              --        --        13.4
--------------------------------------------------------------------------------
</TABLE>

3. REGULATORY MATTERS

A. In April 1997, the Federal Energy Regulatory Commission (FERC) approved a
settlement of Columbia Transmission's rate case which provides for an increase
in revenues to recover the higher costs incurred since 1991. The settlement also
provides an opportunity for the recovery of Columbia Transmission's net
investment in gathering and certain gas processing facilities and 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 settlement allows Columbia Transmission to
retain the gain from the 1996 sale of base gas from one of its storage fields,
as well as certain future base gas sales. Specifically, the settlement permits
Columbia Transmission to retain approximately 95% of the first $60 million
pre-tax gain from future base gas sales. After that level has been reached,
Columbia Transmission would share equally with customers any gain from such
sales. The settlement rates became effective June 1, 1997 and an after-tax
improvement of $12.4 million was recorded in the second quarter of 1997 to
reflect the terms of the settlement, including the base gas sale.

Excluded from the settlement is the environmental cost issue which will be
addressed in the second phase of the proceeding scheduled for hearings during
the fall of 1998. Columbia Transmission continues to collect approximately $18
million per year, subject to refund, for environmental costs.

B. In its September 1993 order on Columbia Transmission's and Columbia Gulf
Transmission Company's (Columbia Gulf) 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. The
FERC issued an order on August 8, 1997, approving a Stipulation and Consent
Agreement that required Columbia Gulf to conduct a 30-day open season on
additional firm mainline capacity up to its certificated design capacity. The
open season concluded on December 15, 1997 and resulted in requested capacity
that exceeded Columbia Gulf's certificated level. Challenges by certain of
Columbia Gulf's customers to the terms of the approved settlement remain pending
at the FERC.

C. On March 1, 1995, Columbia Transmission filed with the FERC to recover $39
million of 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 were recoverable by Columbia Transmission, subject to a
general FERC audit, which has been completed with no 


                                       50
<PAGE>   52

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

adjustment to the amounts billed. With respect to the remaining $20 million of
costs associated with environmental issues, Columbia Transmission and the
parties to the case filed an uncontested offer of settlement in May 1997 that
provided for a resolution of the environmental issues. On June 25, 1997, the
FERC approved the settlement which provided for a refund of $4 million,
including interest. Previously established reserves were sufficient and the
settlement had no effect on 1997 operating income. In addition, the settlement
establishes a method for determining whether Columbia Gulf may seek recovery of
future environmental costs incurred at specific sites and provides for the
withdrawal of a number of related court appeals.

D. On October 31, 1996, Columbia Gulf filed a general rate case with the FERC.
The filing, which reflected a proposed increase in revenues of approximately
$9.6 million, was accepted by the FERC subject to refund and conditions, pending
the outcome of a hearing. On April 29, 1997, Columbia Gulf filed revised rates
reflecting changes required by the FERC's acceptance order. The revised rates,
which reflect an increase in revenues of approximately $8.1 million, went into
effect on May 1, 1997, subject to refund. An agreement in principle settling all
issues and rate levels was reached in January 1998. The FERC staff and active
parties in the proceeding have unanimously agreed to the terms of the
settlement. Management believes that if the settlement is approved as presently
written, it will not have a material impact on Columbia's financial statements.

E. 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 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 the Public Utilities Commission of Ohio (PUCO) approved an
amendment to the 1994 rate case settlement in December 1996. The settlement
permitted 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 were primarily from historic off-system
sales transactions completed or agreed to prior to August 31, 1996. This revenue
mechanism was in lieu of a base rate increase to customers. Additionally, the
settlement provided that Columbia of Ohio would not implement any increase in
base rates before January 1, 1999.

On January 7, 1998, the PUCO approved a second amendment to the 1994 rate case
settlement. The new amendment establishes a five-year funding mechanism that
will enable Columbia of Ohio to expand its Customer CHOICE(R) transportation
program for residential and small commercial customers statewide in 1998. The
funding mechanism authorizes Columbia of Ohio to use off-system sales, capacity
release revenues and fees collected from marketers to offset the cost of
transition capacity that may be generated by expansion of the Customer CHOICE(R)
program, while simultaneously providing Columbia of Ohio with an opportunity to
retain some of the capacity release and off-system sales revenue. The amendment
also extends by one year, to January 1, 2000, Columbia of Ohio's commitment not
to implement any increase in base rates. The amendment gives Columbia of Ohio
the responsibility to manage the transition pipeline capacity costs that will
arise as residential and small commercial customers elect to acquire the
commodity directly from marketers participating in the Customer CHOICE(R)
program, and revenue streams from a number of sources including off-system sales
and capacity releases with which to manage this responsibility. Columbia of Ohio
has accepted the risk for up to 11% of the transition capacity costs to the
extent these costs exceed the revenue streams available to offset them. However,
if after the conclusion of the five-year program the revenues from these sources
more than offset the transition capacity costs, then customers and Columbia of
Ohio will share the credit balance, 75% to the customers and 25% to Columbia of
Ohio.

4. RESTRUCTURING ACTIVITIES

In 1996, Columbia's subsidiaries completed a top-down review of their management
structure and operations in an effort to streamline their organizations and
improve customer service. The studies examined all aspects of Columbia's
operations including the configuration and location of its management.

The transmission subsidiaries restructuring project focused on all processes
within the companies operations. These efforts resulted in streamlined business
functions, improved organizational structures and reduced staff levels.

The distribution segment initiated a restructuring of its headquarters'
operations as part of its ongoing efforts to provide enhanced customer service
and to achieve greater operating efficiencies. These initiatives, which are
designed to streamline and enhance customer service, are continuing. Additional
studies are underway in all of the 


                                       51
<PAGE>   53

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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, with additional expense being recorded.

In the third quarter of 1996, Columbia Energy Group Service Corporation,
Columbia LNG Corporation and Columbia Electric Corporation (Columbia Electric),
formerly TriStar Ventures Corporation, implemented restructuring programs and
moved their corporate headquarters from Wilmington, Delaware to Reston,
Virginia.

As a result of these restructuring programs, it is estimated that 1,412
management, professional, administrative and technical positions will ultimately
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 new corporate center and costs related to the
sale of the former headquarters building. This charge included $52.7 million of
estimated termination benefits. Partially offsetting these charges was a $6
million pre-tax gain on the sale of the former headquarters building. During
1997, Columbia recorded pre-tax charges of $31.1 million in operating expense
representing additional severance and related benefits costs, and additional
relocation costs. This charge included $18.9 million of estimated termination
benefits. As of December 31, 1997, approximately 1,300 employees have been
terminated as a result of these programs. At December 31, 1997, the consolidated
balance sheet reflected an accrual of $16.8 million associated with
restructuring activities.

5. COMMODITY HEDGING ACTIVITIES

A. GAS PRODUCTION. At December 31, 1997, there were 31 open future equivalent
contracts representing a notional quantity amounting to 0.3 Bcf of natural gas
production through February 1998, at an average price of $2.45 per Mcf. A total
of $0.2 million of unrealized gains have been deferred on the consolidated
balance sheet with respect to these open contracts. Additional production is
hedged in the marketplace through a gas marketing affiliate. 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 1997, at an average price
of $2.32 per Mcf. A total of $1.2 million of unrealized gains were deferred on
the consolidated balance sheet with respect to those open contracts at December
31, 1996.

During the year ended December 31, 1997, $0.2 million of gains 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, 1996, $3.7
million of losses were realized on the settlement of these contracts.
These gains and losses are largely offset when the production is sold in the
cash market.

B. MARKETING, PROPANE AND POWER GENERATION. At December 31, 1997, there were
27,423 open future equivalent contracts maturing from January 1998 to January
2008 representing a notional quantity amounting to 272.2 Bcf of natural gas. A
total of $1.14 million of unrealized losses have been deferred on the
consolidated balance sheet with respect to these open contracts. At December 31,
1996, there were 5,173 open contracts through October 1998, representing a
notional quantity amounting to 51.7 Bcf of natural gas. A total of $0.8 million
of unrealized gains were deferred on the consolidated balance sheet with respect
to these open contracts at December 31, 1996. These unrealized losses are
largely offset by gains which are realized when the products are sold.

During the year ended December 31, 1997, $4.7 million of gains were recognized
in operating income on the settlement of natural gas swap contracts. During the
year ended December 31, 1996, $6.3 million of losses were realized on the
settlement of natural gas futures, options and swap contracts. Gains and losses
on propane and gas marketing hedging activities were offset by amounts realized
from the sale of the underlying products.


6. NEW ACCOUNTING STANDARDS

A. In June 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 130, "Reporting Comprehensive Income" (SFAS
No. 130). This statement establishes standards for reporting and display of
comprehensive income and its components in the financial statements. SFAS No.
130 will be effective for financial statements for both interim and annual
periods beginning after December 15, 1997 and reclassification of financial
statements for earlier periods presented will be required for comparative
purposes. Columbia will adopt this statement on January 1, 1998. Columbia does
not anticipate the adoption of this statement will have a significant impact on
the consolidated financial statements.


                                       52
<PAGE>   54

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

B. In June 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 131, "Disclosures about Segments of an
Enterprise and Related Information" (SFAS No. 131). This statement establishes
standards for reporting information about operating segments in annual financial
statements and requires the reporting of selected information about operating
segments in interim financial reports issued to stockholders. It also
establishes standards for related disclosures about products and services,
geographic areas, and major customers. SFAS No. 131 is effective for financial
statements for periods beginning after December 15, 1997, and in the initial
year of application, comparative information for earlier years is to be
restated. Columbia will adopt this statement on January 1, 1998, and does not
expect a significant impact on present segment reporting.

7. INCOME TAXES

The components of income tax expense are as follows:

<TABLE>
<CAPTION>
Year Ended December 31 ($ in millions)               1997       1996       1995
---------------------------------------------------------------------------------
<S>                                                  <C>        <C>        <C>
INCOME TAXES
Current
     Federal                                           82.4       30.4     (284.8)
     State                                              7.2        7.5        8.1
---------------------------------------------------------------------------------
Total Current                                          89.6       37.9     (276.7)
---------------------------------------------------------------------------------
Deferred
     Federal                                           50.4       64.6       69.7
     State                                            (19.6)      14.9       (2.2)
---------------------------------------------------------------------------------
Total Deferred                                         30.8       79.5       67.5
---------------------------------------------------------------------------------
Deferred Investment Credits                            (1.5)      (1.5)      (1.5)
---------------------------------------------------------------------------------
Income taxes included in income before
   extraordinary item                                 118.9      115.9     (210.7)
Deferred taxes related to extraordinary item           --         --         36.9
---------------------------------------------------------------------------------
TOTAL INCOME TAXES                                    118.9      115.9     (173.8)
---------------------------------------------------------------------------------
</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)                                1997                     1996                   1995
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                              <C>         <C>        <C>         <C>       <C>          <C>
Book income (loss) before income taxes and
 extraordinary item                                              392.2                  337.5                 (643.0)
Tax expense (benefit) at statutory Federal income tax rate       137.3       35.0%      118.1       35.0%     (225.0)      35.0%
Increases (reductions) in taxes resulting from:
  State income taxes, net of Federal income tax benefit           (8.1)      (2.1)       16.7        4.9         4.7       (0.7)
  Estimated non-deductible expenses                                0.7        0.2         0.9        0.3         9.0       (1.4)
  Effect of change in deferred taxes previously provided          (1.9)      (0.5)       (4.0)      (1.2)       --         --
  Adjustment to prior year's tax provision
   due to pending settlement                                      (3.2)      (0.8)      (11.3)      (3.4)       --         --
  Other                                                           (5.9)      (1.5)       (4.5)      (1.3)        0.6       (0.1)
-------------------------------------------------------------------------------------------------------------------------------
INCOME TAXES BEFORE EXTRAORDINARY ITEM                           118.9       30.3%      115.9       34.3%     (210.7)      32.8%
-------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       53
<PAGE>   55

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Deferred income taxes result from temporary differences between the financial
statement carrying amounts and the tax basis of existing assets and liabilities.
The principal components of Columbia's net deferred tax liability are as
follows:

<TABLE>
<CAPTION>
At December 31 ($ in millions)                               1997         1996
--------------------------------------------------------------------------------
<S>                                                         <C>          <C>
Deferred tax liabilities
   Property basis differences                                655.3        631.5
   Gas purchase costs                                         52.4         94.4
   Partnership deferrals                                      27.5         23.9
   Other                                                      39.5         14.6
--------------------------------------------------------------------------------
Gross Deferred Tax Liabilities                               774.7        764.4
--------------------------------------------------------------------------------
Deferred tax assets
   Estimated supplier obligations                            (28.8)       (45.4)
   Alternative minimum tax                                    (0.2)       (46.9)
   Estimated rate refunds                                    (12.5)       (25.0)
   Capitalized inventory overheads                           (26.7)       (24.3)
   Unbilled utility revenue                                  (23.2)       (23.9)
   Restructuring costs                                        (8.5)       (21.4)
   Postretirement benefits                                   (10.5)       (16.5)
   Environmental liabilities                                  (8.1)        (8.6)
   Tax loss carryforwards                                    (48.7)       (40.1)
   Off-system sales                                          (21.8)        (7.8)
   Other                                                     (51.2)       (34.3)
--------------------------------------------------------------------------------
Gross Deferred Tax Assets                                   (240.2)      (294.2)
--------------------------------------------------------------------------------
Deferred Tax Asset Valuation Allowance                        34.4         34.7
--------------------------------------------------------------------------------
NET DEFERRED TAX LIABILITY*                                  568.9        504.9
--------------------------------------------------------------------------------
</TABLE>

*Includes net current deferred tax assets of $49.5 million and $52.8 million
reflected in Current Assets for 1997 and 1996, respectively.

As reflected by the valuation allowance in the table above, Columbia had
potential tax benefits of $34.4 million and $34.7 million at December 31, 1997
and 1996, respectively, which were not recognized in the statements of
consolidated income when generated. These benefits resulted from state income
tax operating loss carryforwards which are available to reduce future tax
liabilities. Management believes 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 tax loss carryforward benefits,
net of federal taxes, in 1999 is $2.3 million, in 2000 is $1.2 million, in 2001
is $0.4 million, in 2002 is $0.1 million and beyond is $44.7 million.

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)                 1997          1996          1995
--------------------------------------------------------------------------------
<S>                                          <C>            <C>          <C> 
Service cost                                   28.7          35.0          26.7
Interest cost                                  67.6          70.7          69.9
Actual return on assets                      (236.9)        (81.9)       (202.5)
Net amortization (deferral)                   142.3          (5.1)        124.8
--------------------------------------------------------------------------------
NET PENSION EXPENSE                             1.7          18.7          18.9
--------------------------------------------------------------------------------
CONTRIBUTIONS                                   0.0           0.0           1.2
--------------------------------------------------------------------------------
</TABLE>


                                       54
<PAGE>   56

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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)                 1997         1996
--------------------------------------------------------------------------------
<S>                                                        <C>          <C>    
Plan assets at fair value                                  1,164.6      1,033.9
--------------------------------------------------------------------------------
Actuarial present value of benefit obligations:
   Vested benefits                                           765.8        660.6
   Nonvested benefits                                         60.5         48.7
--------------------------------------------------------------------------------
Accumulated benefit obligation                               826.3        709.3
Effect of projected future salary increases                   62.6        160.6
--------------------------------------------------------------------------------
PROJECTED BENEFIT OBLIGATIONS                                888.9        869.9
--------------------------------------------------------------------------------
Plan assets in excess of projected benefit obligation        275.7        164.0
Unrecognized net gain                                       (390.2)      (281.5)
Unrecognized prior service cost                               48.9         52.6
Unrecognized transition obligation                             5.8          7.0
--------------------------------------------------------------------------------
ACCRUED PENSION COST                                         (59.8)       (57.9)
--------------------------------------------------------------------------------
DISCOUNT RATE ASSUMPTION                                       7.5%         8.0%
--------------------------------------------------------------------------------
ASSET EARNINGS RATE ASSUMPTION                                 9.0%         9.0%
--------------------------------------------------------------------------------
</TABLE>

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

The compensation growth rate assumption was revised downward from 5.0% in 1996
to 3.5% for 1997-1999, and 4.5% thereafter. This equates to a weighted average
of 4.3% over 15 years. As of December 31, 1997, the discount rate assumption was
revised downward to 7.5%. The net effect of these changes was to increase the
accumulated benefit obligation and the projected benefit obligation by $41.7
million and $34.9 million, respectively.

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.


                                       55
<PAGE>   57

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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

<TABLE>
<CAPTION>
OTHER POSTRETIREMENT COSTS ($ in millions)           1997       1996       1995
--------------------------------------------------------------------------------
<S>                                                 <C>        <C>        <C> 
Service Cost                                         13.0       13.8       11.3
Interest Cost                                        23.5       22.4       24.1
Actual return on assets                             (48.3)     (12.5)     (30.0)
Other, net amortization (deferral)                   23.4       (5.4)      16.0
--------------------------------------------------------------------------------
OTHER POSTRETIREMENT COSTS, NET                      11.6       18.3       21.4
--------------------------------------------------------------------------------
CONTRIBUTIONS                                        35.0       39.5       45.6
--------------------------------------------------------------------------------
</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)                   1997        1996
--------------------------------------------------------------------------------
<S>                                                         <C>         <C>
Accumulated postretirement benefit obligation:
Retirees                                                     170.5       151.0
Fully eligible active plan participants                       50.5        54.5
Other participants                                            88.8        81.7
--------------------------------------------------------------------------------
Total accumulated postretirement benefit obligation          309.8       287.2
Plan assets at fair value                                   (242.9)     (179.6)
--------------------------------------------------------------------------------
Accumulated postretirement benefit
    obligation in excess of plan assets                       66.9       107.6
Unrecognized actuarial net gain                              129.9       117.5
Less: Fourth quarter contributions                             7.4         6.6
--------------------------------------------------------------------------------
ACCRUED POSTRETIREMENT BENEFIT COST                          189.4       218.5
--------------------------------------------------------------------------------
DISCOUNT RATE ASSUMPTION                                       7.5%        8.0%
--------------------------------------------------------------------------------
MEDICAL COST TREND                                             5.5%        5.5%
--------------------------------------------------------------------------------
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.

The compensation growth rate assumption was revised downward from 5.0% in 1996
to 3.5% for 1997-1999, and 4.5% thereafter. This equates to a weighted average
of 4.3% over 15 years. As of December 31, 1997, the discount rate assumption was
revised downward to 7.5% from 8.0%. The medical cost trend rate remained at 5.5%
for December 31, 1997. The net effect of these changes was a $13.3 million
increase 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 $17.0
million and other postretirement costs by $3.0 million in 1997.

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 $3.9
million, and $3.3 million were made to the retiree life insurance VEBA trust in
1997 and 1996, respectively.

Columbia's regulated subsidiaries participate in funding for retiree medical
costs, using two trusts and a 401(h) account. Columbia's non-regulated companies
have elected not to fund retiree health care costs, and make contributions to
the trust accounts on a pay-as-you-go basis. Contributions of approximately
$31.1 million and $36.2 million were made to these retiree medical trusts in
1997 and 1996, respectively.

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 


                                       56
<PAGE>   58

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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, 1997, are as follows:

<TABLE>
<CAPTION>
                                               Options
                                    ----------------------------
                                    Without Stock    With Stock         Options
                                     Appreciation   Appreciation         Price
                                        Rights         Rights            Range
-----------------------------------------------------------------------------------
<S>                                 <C>             <C>            <C>
Outstanding  at December 31, 1994       484,965        156,150     $   34.30-$46.68
  Granted                                93,000             --     $   28.99-$31.05
  Exercised                             (33,245)        (6,100)    $   28.99-$38.30
  Cancelled                             (20,400)            --     $   34.30-$46.68
-----------------------------------------------------------------------------------
Outstanding at December 31, 1995        524,320        150,050     $   28.99-$46.68
  Granted                               100,000             --     $        48.6875
  Exercised                            (209,625)       (66,860)    $   28.99-$46.68
  Forfeited                              (9,020)        (7,260)    $   34.30-$46.68
-----------------------------------------------------------------------------------
Outstanding at December 31, 1996        405,675         75,930     $ 28.99-$48.6875
  Granted                             1,133,350             --     $58.375-$71.0938
  Exercised                            (183,138)       (48,790)    $ 28.99-$63.6875
  Forfeited                             (41,962)        (3,240)    $ 34.30-$63.6875
===================================================================================
OUTSTANDING AT DECEMBER 31, 1997      1,313,925         23,900     $ 28.99-$71.0938
===================================================================================
EXERCISABLE AT DECEMBER 31, 1997        596,824         23,900     $ 28.99-$63.6875
===================================================================================
</TABLE>

Regarding the stock options granted in 1997, such options vest ratably over
three years. Regarding the stock options granted in 1996, 50% of such options
vested in 1996 and the other 50% vested in 1997. All of the stock options
granted in 1995 had vested in 1995.

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

<TABLE>
<CAPTION>
                                               1997          1996          1995
--------------------------------------------------------------------------------
<S>                                           <C>           <C>           <C>   
Outstanding at January 1                      $42.88        $41.31        $42.69
Granted during the year                        63.40         48.69         29.10
Exercised during the year                      44.31         41.07         35.36
Forfeited during the year                      62.01         44.15            --
Cancelled during the year                         --            --         40.61
OUTSTANDING AT DECEMBER 31                     59.37         42.88         41.31
EXERCISABLE AT DECEMBER 31                     54.70         42.21         41.31
--------------------------------------------------------------------------------
</TABLE>

In addition to the options, contingent stock awards totaling 27,500 shares were
granted to two key executives in 1995. All of these shares vested and 22,820
shares have been issued (net of amounts withheld to pay taxes). In 1996,
contingent stock awards totaling 1,500 shares were granted to one key executive
and all 1,500 shares vested 


                                       57
<PAGE>   59

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

and were issued during 1996. There were no contingent stock awards granted in
1997. Restricted stock awards totaling 29,785 shares were granted to one key
executive in 1996 of which 5,957 shares vested during 1997.

During 1997, 1996 and 1995, $3.2 million, $2.1 million and $1.1 million were
expensed for the long-term incentive plans, respectively.

Had compensation cost been determined consistent with the provisions of the SFAS
No. 123 fair value method (See Note 1), Columbia's net income would have been
$255.6 million (earnings per share of $4.61 and diluted earnings per share of
$4.59) in 1997. The effect on Columbia's net income and earnings per share for
both 1996 and 1995 would have been immaterial. The fair value of each option
grant is estimated on the date of grant using the Black-Scholes option-pricing
model with the following assumptions used for grants in 1997, 1996 and 1995:
dividend yield of zero percent for 1997 and 1996 to reflect dividend equivalents
applicable to awards granted and 1.18% for 1995; expected volatility ranging
from 18.41% to 19.29% for 1997 and 20.12% for both 1996 and 1995; risk free
interest rates ranging from 5.86% to 6.89% for 1997, 6.58% for 1996, and 5.93%
and 6.39% for 1995; and expected lives of seven years. The weighted-average fair
market value of options granted were $24.85, $19.80 and $9.72 for 1997, 1996 and
1995, respectively.

10. 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)                               1997           1996
--------------------------------------------------------------------------------
<S>                                                       <C>            <C>
Columbia Energy Group 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                                 2.7            2.5
Other                                                         0.8            1.3
================================================================================
TOTAL LONG-TERM DEBT                                      2,003.5        2,003.8
================================================================================
</TABLE>

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

<TABLE>
<CAPTION>
($ in millions)
--------------------------------------------------------------------------------
<S>                                                                        <C>
1998                                                                         0.6
1999                                                                         0.5
2000                                                                       311.3
2001                                                                         0.5
2002                                                                       281.7
--------------------------------------------------------------------------------
</TABLE>

11. SHORT-TERM DEBT AND CREDIT FACILITIES

In November 1995, Columbia entered into an unsecured bank revolving credit
agreement (Credit Facility). The Credit Facility is a five-year revolving credit
agreement maturing November 2000 and is used to support outstanding commercial
paper and to meet other short-term requirements. The Credit Facility had an
initial commitment amount of $1 billion with scheduled quarterly commitment
reductions of $25 million beginning on December 31, 1997. As of December 31,
1997, the commitment amount was $975 million. 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, 1997 is 0.11%. The Credit Facility contains certain covenants that
must be met to borrow funds including 


                                       58
<PAGE>   60

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

restrictions on the incurrence of liens, a maximum leverage ratio, and a minimum
consolidated net worth. At December 31, 1997, Columbia had outstanding $120
million under the Credit Facility at an average interest rate of 6.17%. At
December 31, 1996, Columbia had outstanding $250 million under the Credit
Facility at an average interest rate of 6.44%. The maximum credit facility
indebtedness outstanding during the year occurred on January 1, 1997 in the
amount of $250 million at an average interest rate of 6.44%.

The Credit Facility provides for the issuance of up to $100 million of standby
letters of credit. 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, 1997, Columbia had $42.7 million of letters of credit outstanding
under the 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, 1997, fees for letters of credit
issued in connection with certain financial obligations were at a rate of 0.19%.

Columbia has an $850 million commercial paper program authorized and rated by
the rating agencies. At December 31, 1997, Columbia had commercial paper
outstanding of $208.1 million (net of discount) at a weighted average interest
rate of 6.42%. No commercial paper borrowings were made during 1996. The maximum
commercial paper indebtedness outstanding during the year occurred on December
4, 1997, in the amount of $326.4 million at an average interest rate of 5.97%.

In addition, Columbia had a $75 million letter of credit outstanding at December
31, 1997, as a guarantee of certain transactions of its wholly owned marketing
affiliate.

At December 31, 1997, approximately $7.5 million of investments were pledged as
collateral on outstanding letters of credit related to Columbia's wholly owned
insurance captive.

In March 1998, Columbia replaced the Credit Facility with two new unsecured bank
revolving credit facilities that total $1.35 billion (New Credit Facilities).
The New Credit Facilities consist of a $900 million five-year revolving credit
facility and a $450 million 364-day revolving credit facility with a one-year
term loan option. The five-year facility will provide for the issuance of up to
$300 million of letters of credit. Interest rates on borrowings under the New
Credit Facilities are based upon the London Interbank Offered Rate or Citibank's
publicly announced "base rate." Facility fee payments and fees for letters of
credit are based upon Columbia's public debt ratings. At Columbia's current
rating, the facility fee charged on the $900 million credit facility is 0.11%
and on the $450 million credit facility is 0.085%.

12. 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.

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. Columbia utilizes standby letters
of credit (See Note 11) and does not believe it is practicable to estimate their
fair value.

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 ($3.7 million for 1997 and $4.0
million for 1996) whose estimated fair values are based on the present value of
estimated future cash flows using an estimated rate for similar loans. Long-term
investments also include pledged assets of $7.5 million for 1997, whose
estimated fair value is based on the trading value provided by a financial
institution. The financial instruments included in long-term investments are
primarily reflected in Investments and Other Assets on the consolidated balance
sheets. Long-term investments for which it is practicable to estimate fair value
had carrying amounts of $11.2 million and $4.0 million, and estimated fair
values of $10.8 million and $3.6 million at December 31, 1997 and 1996,
respectively. Long-term investments for which it is not practicable to estimate
fair value had carrying amounts of $4.2 million at December 


                                       59
<PAGE>   61

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

31, 1996. There are no long-term investments for which it is not practicable to
estimate fair value at December 31, 1997.

LONG-TERM DEBT

The estimated fair value of Columbia's debentures, including accrued interest,
is based on estimates provided by brokers. Long-term debt of $2,012.9 million
and $2,012.9 million at December 31, 1997 and 1996, have estimated fair values
of $2,051.6 million and $1,948.1 million, respectively.


13. OTHER COMMITMENTS AND CONTINGENCIES

A. CAPITAL EXPENDITURES. Capital expenditures for 1998 are currently estimated
at $555 million. Of this amount, $250 million is for transmission and storage
operations, $162 million for distribution operations, $86 million for
exploration and production operations, $46 million for marketing, propane and
power generation operations and $11 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.

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.

Columbia Electric Corporation (Columbia Electric), formerly TriStar Ventures
Corporation, a wholly owned subsidiary of Columbia, holds indirectly through
various Columbia Electric subsidiaries, both general and limited partnership
interests in Pedricktown Cogeneration Limited Partnership and Vineland
Cogeneration Limited Partnership (the "Partnerships"), which own and operate
project-financed non-utility power generation facilities in New Jersey. The
assets of the Partnerships, including plant facilities and contract rights, have
been pledged as collateral for loans to a bank syndicate in the case of
Pedricktown, or to an indenture trustee for the benefit of certain bondholders
in the case of Vineland. Columbia Electric's investment in the Partnerships, as
of December 31, 1997, amounted to $17 million.

D. INTERNAL REVENUE SERVICE (IRS) AUDIT. A settlement with the IRS of Columbia's
1991 through 1994 federal income tax returns has been concluded. The field audit
for 1995 has been finalized and management believes adequate reserves have been
established for issues in the 1995 tax return.

E. OPERATING LEASES. Payments made in connection with operating leases are
charged to operation and maintenance expense as incurred. Such amounts were
$62.9 million in 1997, $60.9 million in 1996 and $61.6 million in 1995.

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> 
1998                                                                        30.1
1999                                                                        28.2
2000                                                                        24.2
2001                                                                        22.9
2002                                                                        22.4
After                                                                      205.5
--------------------------------------------------------------------------------
</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.


                                       60
<PAGE>   62

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

A subsidiary has received notice from the United States Environmental Protection
Agency (EPA) that it is among several parties responsible under federal law for
placing wastes at a Superfund site. It is sharing in the cost for remediation of
this site. Considering known facts, existing laws and possible insurance and
rate recoveries, management does not believe the identified Superfund matter
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, the
transmission subsidiaries continue 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 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, "Accounting and Disclosure Relating to Loss
Contingencies," SFAS No. 5 and American Institute of Certified Public
Accountants Statement of Position 96-1, "Environmental Remediation Liabilities."

Columbia Transmission received EPA approval for and completed characterization
of 73 major facilities, approximately 2,800 liquid removal points and
approximately 900 mercury measurement stations in 1997. In addition,
approximately 400 mercury measuring stations were remediated.

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.
Columbia Transmission conducted assessments at 160 sites and, based on these
assessment results, performed remedial activities in varying degrees at
approximately 85 locations.

As a result of these 1997 activities, Columbia Transmission recorded in 1997 an
additional liability of $16.8 million. Actual expenditures of approximately
$17.1 million during 1997 charged to the liability resulted in a remaining
liability of $125.4 million. Columbia Transmission's environmental cash
expenditures are expected to be approximately $18 million in 1998 and up to $20
million annually until the AOC is satisfied. These expenditures will be charged
against Columbia Transmission's previously recorded liability. Consistent with
Statement of Financial Accounting Standards No. 71, a regulatory asset has been
recorded to the extent environmental expenditures are expected to be recovered
through rates. Columbia Transmission continues to pursue recovery of
environmental expenditures from its insurance carriers; however, at this time,
management is unable to determine the total amount or final disposition of any
recovery.


                                       61
<PAGE>   63

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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. At this time, Columbia Transmission is unable 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 seven 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
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.

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 $129.1 million
for Columbia at December 31, 1997. 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.

14. INTEREST INCOME AND OTHER, NET

<TABLE>
<CAPTION>
Year Ended December 3l ($ in millions)                 1997      1996      1995
--------------------------------------------------------------------------------
<S>                                                    <C>       <C>      <C> 
Interest income                                        21.0      13.4      22.8
Sale of Columbia Development                             --       6.9     (77.8)
Miscellaneous                                          19.4       5.8      (3.2)
--------------------------------------------------------------------------------
TOTAL INTEREST INCOME AND OTHER, NET                   40.4      26.1     (58.2)
--------------------------------------------------------------------------------
</TABLE>


15. INTEREST EXPENSE AND RELATED CHARGES

<TABLE>
<CAPTION>
Year Ended December 31 ($ in millions)                1997       1996      1995
--------------------------------------------------------------------------------
<S>                                                  <C>        <C>       <C>
Interest on emergence, including amortization of
  discounts on long-term debt                           --         --     982.9
Interest on debentures                               140.4      140.4        --
Interest on short-term debt                            8.2       11.7      15.1
Interest on rate refunds                               3.4        3.9      17.7
Interest on prior years' taxes                         9.1        8.3      17.6
Allowance for borrowed funds used
  and interest during construction                    (3.5)       2.5     (52.4)
Other interest charges                                  --         --       7.5
--------------------------------------------------------------------------------
TOTAL INTEREST EXPENSE AND RELATED CHARGES           157.6      166.8     988.4
--------------------------------------------------------------------------------
</TABLE>

16. 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 17 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 service and transportation for residential, commercial and 


                                       62
<PAGE>   64

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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 related energy services to distribution companies,
independent power producers and other retail 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.

<TABLE>
<CAPTION>
($ in millions)                              1997          1996          1995
--------------------------------------------------------------------------------
<S>                                         <C>           <C>           <C>
REVENUES
    Transmission and Storage
     Unaffiliated                             516.9         456.2         436.0
     Intersegment                             332.9         354.6         324.3
--------------------------------------------------------------------------------
     TOTAL                                    849.8         810.8         760.3
--------------------------------------------------------------------------------
    Distribution
     Unaffiliated                           2,283.6       2,120.4       1,780.6
     Intersegment                              12.7           7.3           2.5
--------------------------------------------------------------------------------
     TOTAL                                  2,296.3       2,127.7       1,783.1
--------------------------------------------------------------------------------
    Exploration and Production
     Unaffiliated                              44.3          45.5         111.5
     Intersegment                              69.0          59.0          69.1
--------------------------------------------------------------------------------
     TOTAL                                    113.3         104.5         180.6
--------------------------------------------------------------------------------
    Marketing, Propane
     and Power Generation
     Unaffiliated                           2,208.9         731.5         307.1
     Intersegment                              66.8          84.9           6.2
--------------------------------------------------------------------------------
     TOTAL                                  2,275.7         816.4         313.3
--------------------------------------------------------------------------------
    Adjustments and eliminations
     Unaffiliated                              (0.1)          0.4            --
     Intersegment                            (481.4)       (505.8)       (402.1)
--------------------------------------------------------------------------------
     TOTAL                                   (481.5)       (505.4)       (402.1)
--------------------------------------------------------------------------------
    CONSOLIDATED                            5,053.6       3,354.0       2,635.2
--------------------------------------------------------------------------------
</TABLE>


                                       63
<PAGE>   65

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)


<TABLE>
<CAPTION>
($ in millions)                               1997          1996          1995
--------------------------------------------------------------------------------
<S>                                         <C>           <C>           <C>
OPERATING INCOME (LOSS)
    Transmission and Storage                  264.3         207.8         213.0
    Distribution                              224.2         226.0         163.6
    Exploration and Production                 30.9          30.0           3.7
    Marketing, Propane
      and Power Generation                     (2.9)         12.5          12.2
    Corporate                                  (7.1)          1.9          (2.3)
--------------------------------------------------------------------------------
    CONSOLIDATED                              509.4         478.2         390.2
--------------------------------------------------------------------------------
DEPRECIATION & DEPLETION
    Transmission and Storage                  104.3         102.6         103.8
    Distribution                               78.2          74.4          70.9
    Exploration and Production                 27.6          28.8          86.9
    Marketing, Propane
      and Power Generation                      5.2           3.1           2.6
    Adjustments and eliminations                6.0           6.3           5.8
--------------------------------------------------------------------------------
    CONSOLIDATED                              221.3         215.2         270.0
--------------------------------------------------------------------------------
IDENTIFIABLE ASSETS
    Transmission and Storage                2,758.7       2,761.2       2,978.9
    Distribution                            2,753.5       2,648.3       2,295.7
    Exploration and Production                564.6         421.7         412.4
    Marketing, Propane
      and Power Generation                    613.2         289.0         125.8
    Corporate and unallocated                 471.9         504.6         604.6
    Adjustments and eliminations             (549.6)       (620.2)       (360.4)
--------------------------------------------------------------------------------
    CONSOLIDATED                            6,612.3       6,004.6       6,057.0
--------------------------------------------------------------------------------
CAPITAL EXPENDITURES
    Transmission and Storage                  244.9         142.7         172.5
    Distribution                              159.5         148.4         151.8
    Exploration and Production                158.7          12.1          86.8
    Marketing, Propane
        and Power Generation                   15.0           6.3           6.6
    Corporate                                   5.3           5.3           4.1
    Adjustments and eliminations              (23.1)           --            --
--------------------------------------------------------------------------------
    CONSOLIDATED                              560.3         314.8         421.8
--------------------------------------------------------------------------------
</TABLE>


                                       64
<PAGE>   66

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

17. QUARTERLY FINANCIAL DATA (UNAUDITED)

Quarterly financial data does not always reveal the trend of the Columbia's
business operations due to 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>
1997
   Operating Revenues                         1,527.7       810.7         995.0        1,720.2
   Operating Income                             256.6        84.3          29.7          138.8
   Net Income on Common Stock                   162.7(a)     34.9(b)        0.1           75.6(c)

   Per Share Amounts
     Earnings Per Share                          2.94        0.63            --           1.36
     Diluted Earnings Per Share                  2.93        0.63            --           1.35
----------------------------------------------------------------------------------------------
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) on Common Stock            151.3         8.2(d)       (6.1)(e)       68.2(f)

   Per Share Amounts
     Earnings (Loss) Per Share                   2.99        0.15         (0.11)          1.24
     Diluted Earnings (Loss)  Per Share          2.98        0.15         (0.11)          1.23
----------------------------------------------------------------------------------------------
</TABLE>

(a) Includes $12.8 million reduction in state income tax expense and $5.5
    million gain on deactivation of a storage field.

(b) Includes $12.4 million from Columbia Transmission's sale of base gas, as
    agreed to under the terms of Columbia Transmission's rate settlement.

(c) Includes the net income effect of $6.0 million for the sale of coal assets.

(d) Includes a decrease in net income of $18.6 million to reflect severance and
    benefit costs associated with ongoing restructuring 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.

(e) Includes a decrease in net income of $2.5 million to reflect severance and
    benefit costs associated with ongoing restructuring activities.

(f) Includes a decrease in net income of $11.1 million to reflect severance and
    benefit costs associated with ongoing restructuring activities.

18. EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)

On August 7, 1997, Columbia Natural Resources, Inc. (Columbia Resources)
acquired Alamco, a gas and oil production company operating in the Appalachian
Basin. 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 Alamco for August 7, 1997, through year-end
and the operations and reserves of Columbia Development for 1995.

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.


                                       65
<PAGE>   67

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

<TABLE>
<CAPTION>
RESERVE QUANTITY INFORMATION
-----------------------------------------------------------------------------------
                                                                      Oil and Other
                                                             Gas        Liquids
Proved Reserves                                             (Bcf)     (000 Bbls)
-----------------------------------------------------------------------------------
<S>                                                        <C>        <C>   
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
   Revisions of previous estimate                            69.5          (139)
   Extensions, discoveries
    and other additions                                      33.2            59
   Production                                               (34.7)         (210)
   Purchase of reserves-in-place (b)                         88.0         1,216
-----------------------------------------------------------------------------------
RESERVES AS OF DECEMBER 31, 1997                            800.5         1,700
-----------------------------------------------------------------------------------
Proved developed reserves as of  December 31,
  1995                                                      471.6         1,608
  1996                                                      518.3           730
  1997                                                      653.2         1,330
-----------------------------------------------------------------------------------
</TABLE>

(a) Includes the sale of Columbia Development.
(b) Includes the purchase of Alamco.


CAPITALIZED COSTS

<TABLE>
<CAPTION>
($ in millions)                                   1997       1996       1995
--------------------------------------------------------------------------------
<S>                                             <C>        <C>        <C>
CAPITALIZED COSTS AT YEAR END
    Proved properties                            628.4      475.4      486.2
    Unproved properties (a)                       31.8       27.4       30.1
--------------------------------------------------------------------------------
Total capitalized costs                          660.2      502.8      516.3
Accumulated depletion                           (196.0)    (146.4)    (141.1)
--------------------------------------------------------------------------------
NET CAPITALIZED COSTS                            464.2      356.4      375.2
--------------------------------------------------------------------------------
COSTS CAPITALIZED DURING YEAR (b)
    Acquisition - Unproved properties              0.1        0.7        1.1
    Exploration                                    1.0        2.7        4.3
    Development                                  132.4        8.7       15.5
--------------------------------------------------------------------------------
COSTS CAPITALIZED                                133.5       12.1       20.9(c)
--------------------------------------------------------------------------------
</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 of Notes to Consolidated Financial Statements of $1.4
    million in 1997, $0.9 million in 1996 and $1.7 million in 1995.
(c) Excludes capital expenditures for properties sold.


                                       66
<PAGE>   68

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

OTHER EXPLORATION AND PRODUCTION DATA

<TABLE>
<CAPTION>
                                                     1997       1996       1995
--------------------------------------------------------------------------------
<S>                                                  <C>        <C>        <C>
Average sales price per Mcf of gas ($)(a)             2.63       2.84       1.96
Average sales price per barrel
     of oil and other liquids ($)                    17.99      19.07      16.17
Production (lifting) cost per
     dollar of gross revenue ($)                      0.24       0.22       0.27
Depletion rate per dollar
     of gross revenue ($)                             0.28       0.29       0.49
--------------------------------------------------------------------------------
</TABLE>

(a) Includes the effect of hedging activities.


<TABLE>
<CAPTION>
HISTORICAL RESULTS OF OPERATIONS
-----------------------------------------------------------------------------------------------------------
                                  Appalachia                   Southwest                     Total
                           ------------------------      --------------------      ------------------------
($ in millions)            1997      1996      1995      1997    1996    1995      1997      1996      1995
-----------------------------------------------------------------------------------------------------------
<S>                        <C>       <C>       <C>       <C>     <C>     <C>       <C>       <C>      <C>
Gross revenues
    Unaffiliated           27.4      43.1      46.6        --      --    60.1      27.4      43.1     106.7
    Affiliated             69.0      58.8      32.8        --      --    35.9      69.0      58.8      68.7
Production costs           23.3      21.7      21.2        --      --    26.7      23.3      21.7      47.9
Depletion                  26.6      28.8      39.5        --      --    47.0      26.6      28.8      86.5
Income tax expense         14.3      15.1       6.5        --      --     7.8      14.3      15.1      14.3
-----------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS      32.2      36.3      12.2        --      --    14.5      32.2      36.3      26.7
-----------------------------------------------------------------------------------------------------------
</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.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

<TABLE>
<CAPTION>
                                                           Appalachia
--------------------------------------------------------------------------------
($ in millions)                                    1997        1996        1995
--------------------------------------------------------------------------------
<S>                                             <C>         <C>         <C>    
Future cash inflows                             2,503.0     2,389.1     1,793.8
Future production costs                          (719.9)     (715.5)     (606.7)
Future development costs                         (182.7)     (165.8)     (166.3)
Future income tax expense                        (557.5)     (499.7)     (327.1)
--------------------------------------------------------------------------------
Future net cash flows                           1,042.9     1,008.1       693.7
Less 10% discount                                 582.2       574.4       377.7
--------------------------------------------------------------------------------
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
  NET CASH FLOW                                   460.7       433.7       316.0
--------------------------------------------------------------------------------
</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%
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.


                                       67
<PAGE>   69

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)                                1997          1996          1995
--------------------------------------------------------------------------------
<S>                                          <C>           <C>           <C>  
Beginning of year                             433.7         316.0         406.3
--------------------------------------------------------------------------------
Gas and oil sales,
   net of production costs                    (73.1)        (80.2)       (124.3)

Net changes in prices
   and production costs                      (107.8)        170.4         132.7

Change in future
   development costs                          (16.9)          0.5         (49.7)

Extensions, discoveries
   and other additions,
   net of related costs                        51.9           9.4         106.5

Revisions of previous
   estimates, net of
   related costs                               64.0          90.1          72.5

Sales of reserves-in-place                     (4.1)        (18.4)       (195.6)

Purchases of reserves-in-place                 67.0            --            --

Accretion of discount                          64.3          46.0          55.2

Net change in income taxes                    (30.5)        (65.3)        (64.9)

Timing of production
   and other changes                           12.2         (34.8)        (22.7)
--------------------------------------------------------------------------------
END OF YEAR                                   460.7         433.7         316.0
--------------------------------------------------------------------------------
</TABLE>


                                       68
<PAGE>   70
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

                                                                     Schedule II

                       VALUATION AND QUALIFYING ACCOUNTS
                     Columbia Energy Group and Subsidiaries
                           Year Ended December 31,
                               ($ in Millions)

<TABLE>
<CAPTION>
                                                                 Additions - Charged to
                                                            ----------------------------------
                                           Beginning                                Other                                    Ending
Description                                 Balance           Income              Accounts(a)        Deductions(b)           Balance
------------------------------------------------------------------------------------------------------------------------------------
<S>                                        <C>                <C>                 <C>                <C>                     <C>
Reserves deducted in the balance sheet
 from the assets to which they apply:
     
     Allowance for doubtful accounts

          1997                                16.2              29.8                 19.8                47.1                   18.7
          
          1996                                12.3              25.6                 17.7                39.4                   16.2

          1995                                11.6              31.6                 11.3                42.2                   12.3
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

(a) Reflects reclassifications 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.



                                       69
<PAGE>   71

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 1998 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, 45, Chairman, Chief Executive Officer and President of
Columbia (since 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 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, 51, Senior Vice President and Chief Legal Officer of
Columbia and Columbia Energy Group Service Corporation since August 1995; Senior
Vice President 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, 53, Senior Vice President and Chief Financial Officer of
Columbia and Columbia Energy Group Service Corporation since October 1993.
Senior Vice President and Assistant Chief Financial Officer of Columbia and
Columbia Energy Group Service Corporation from 1989 to 1993.

CATHERINE GOOD ABBOTT, 47, Chief Executive Officer and President of Columbia Gas
Transmission Corporation and Chief Executive Officer of 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.

RAY R. KASKEL, 60, Senior Vice President of Columbia Energy Group Service
Corporation since April 1997. President and Chief Executive Officer of Enron
Liquid Services Corp. from 1993 to April 1997. President and Chief Operating
Officer of Enron Europe from 1990 to 1993. Prior to 1990, Mr. Kaskel held
various executive positions at Enron Corporation and was President of Terrance
Development Corporation.


ITEM 11. EXECUTIVE COMPENSATION

Information required by this item is contained in Columbia's Proxy Statement
related to the 1998 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 1998 Annual Meeting of Stockholders, to be filed pursuant to
Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by
reference.


                                       70
<PAGE>   72

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information required by this item is contained in Columbia's Proxy Statement
related to the 1998 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 73 through 75 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 U.S. Securities and Exchange
Commission 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 December 19, 1997, containing a Press Release
issued that day announcing that Columbia Energy Services had begun marketing
electricity in addition to natural gas.

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, as amended (the Act), 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 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 U.S. 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.


                                       71
<PAGE>   73

                                   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.

                                    COLUMBIA ENERGY GROUP
                                        (Registrant)
Dated: March 18, 1998
                                    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>
March 18, 1998  /s/ Oliver G. Richard III        March 18, 1998  /s/ J. Bennett Johnston
                Director (Principal                              J. Bennett Johnston
                Executive Officer)                               Director

March 18, 1998  /s/ Richard F. Albosta           March 18, 1998  /s/ Malcolm Jozoff
                Richard F. Albosta                               Malcolm Jozoff
                Director                                         Director

March 18, 1998  /s/ Robert H. Beeby              March 18, 1998  /s/ William E. Lavery
                Robert H. Beeby                                  William E. Lavery
                Director                                         Director

March 18, 1998  /s/ Wilson K. Cadman             March 18, 1998  /s/ Gerald E. Mayo
                Wilson K. Cadman                                 Gerald E. Mayo
                Director                                         Director

March 18, 1998  /s/ Jeffrey W. Grossman          March 18, 1998  /s/ Michael W. O'Donnell
                Jeffrey W. Grossman                              Michael W. O'Donnell
                Vice President & Controller                      Senior Vice President
                (Principal Accounting Officer)                   (Chief Financial Officer)

March 18, 1998  /s/ James P. Heffernan           March 18, 1998  /s/ Douglas E. Olesen
                James P. Heffernan                               Douglas E. Olesen
                Director                                         Director

March 18, 1998  /s/ Karen L. Hendricks           March 18, 1998  /s/ James R. Thomas, II
                Karen L. Hendricks                               James R. Thomas, II
                Director                                         Director

March 18, 1998  /s/ Donald P. Hodel              March 18, 1998  /s/ William R. Wilson
                Donald P. Hodel                                  William R. Wilson
                Director                                         Director

March 18, 1998  /s/ Malcolm T. Hopkins
                Malcolm T. Hopkins
                Director
</TABLE>


                                       72
<PAGE>   74

EXHIBIT INDEX (continued)

         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.
  3-C *     -    Certificate of Ownership and Merger, Merging Columbia
                  Energy Group, Inc. into The Columbia Gas System, Inc.
  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.
* Filed herewith.


                                       73
<PAGE>   75

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 November 28, 1995,                         1-1098       10-CB
                  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-CD *   -    Credit Agreement for $450,000,000, dated March 11, 1998,
                  among Columbia Energy Group and certain banks party thereto and
                  Citibank, N.A. as Administrative and Syndication Agent.
  10-CE *   -    Credit Agreement for $900,000,000, dated March 11, 1998,
                  among Columbia Energy Group and certain banks party thereto and
                  Citibank, N.A. as Administrative and Syndication Agent.
  10-CF *   -    Memorandum of Understanding among the Millennium Pipeline
                  Project partners (Columbia Transmission, West Coast Energy, MCN
                  Investment Corp. and TransCanada Pipelines Limited) dated
                  December 1, 1997
  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                     1-1098       10-CM
                  Corporation as filed with the United States Bankruptcy
                  Court for the District of Delaware on January 18, 1994.
  12 *      -    Statements of Ratio of Earnings to Fixed Charges
                  and Preferred Stock Dividends.
  21 *      -    Subsidiaries of Columbia Energy Group
</TABLE>

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


                                       74
<PAGE>   76

EXHIBIT INDEX (continued)

<TABLE>
<CAPTION>
                                                                                             Reference 
                                                                                         File No.   Exhibit
                                                                                         --------   -------
<S>                                                                                      <C>        <C>
  23-A *   -     Letter report, dated January 23, 1998, and the written
                 consent to the filing and use of information contained in such
                 letter report, Reports and Registration Statements filed during
                 1998, of Ryder Scott Company Petroleum Engineers, independent
                 petroleum and natural gas consultants.
  23-B *   -     Written consent of Arthur Andersen LLP,
                 independent public accountants, to the
                 incorporation by reference of their report
                 included in the 1997 Annual Report on Form
                 10-K of Columbia Energy Group and
                 their report included in Columbia Energy Group's
                 1997 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, 1997.
</TABLE>

* Filed herewith.


                                       75