<PAGE>   1


             As filed with the United States Securities and Exchange
                         Commission on March 28, 2001.


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

                                    FORM 10-K

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

                   For the Fiscal Year Ended DECEMBER 31, 2000

                                       or

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

                  For the Transition Period from _____ to _____

                    C O L U M B I A  E N E R G Y  G R O U P
             (Exact name of registrant as specified in its charter)

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

      801 E. 86th Avenue,  Merrillville, IN                     46410
---------------------------------------------            ------------------
     (Address of Principal Executive Office)                  (Zip Code)

        Registrant's telephone number, including area code (877) 647-5990

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

Name of Each Exchange on Which Registered
-----------------------------------------
New York Stock Exchange

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

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

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

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

As of November 1, 2000, all shares of the registrant's Common Shares, $.01 par
value, were issued and outstanding, all held beneficially and of record by
NiSource, Inc.

THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I. (1) (A)
AND (B) OF FORM 10-K AND IS FILING THIS FORM 10-K UNDER THE REDUCED DISCLOSURE
FORMAT.


Documents Incorporated by Reference                       NONE
<PAGE>   2
                                    CONTENTS




<TABLE>
<CAPTION>
                                                                                                  Page
Part I                                                                                            No.
                                                                                                  ----

<S>                                                                                               <C>
         Item 1.  Business...................................................................      3

         Item 2.  Properties.................................................................      6

         Item 3.  Legal Proceedings..........................................................      8

         Item 4.  Submission of Matters to a Vote of Security Holders........................      9

Part II

         Item 5.  Market for the Registrant's Common Equity and Related Stockholder Matters..      9

         Item 6.  Selected Financial Data....................................................     10

         Item 7.  Management's Discussion and Analysis of Financial Condition and
                  Results of Operations......................................................     11

         Item 8.  Financial Statements and Supplementary Data................................     28

         Item 9.  Change In and Disagreements with Accountants on Accounting and
                  Financial Disclosure.......................................................     58

Part III

         Item 10. Directors and Executive Officers of the Registrant.........................     58

         Item 11. Executive Compensation.....................................................     58

         Item 12. Security Ownership of Certain Beneficial Owners and Management.............     58

         Item 13. Certain Relationships and Related Transactions.............................     58

Part IV

         Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............     58

         Signatures..........................................................................     59

         Exhibits............................................................................     60
</TABLE>


                                       2
<PAGE>   3
ITEM 1. BUSINESS


                                     PART I

Columbia Energy Group (Columbia) and its subsidiaries are primarily engaged in
natural gas transmission, natural gas distribution, and exploration for and
production of natural gas and oil. 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 19 direct subsidiaries.

Merger with NiSource Inc.
On November 1, 2000, NiSource Inc. (NiSource) completed the acquisition of
Columbia for an aggregate consideration of approximately $6 billion, with 30% of
the consideration paid in NiSource common stock and the remaining 70% paid in
cash and Stock Appreciation Income Linked Securities(SM) (SAILS(SM)). In
addition, NiSource assumed approximately $2 billion in Columbia debt.

Presentation of Segment Information
Columbia revised its presentation of its primary business segment information
beginning with the reporting of second quarter 2000 results. As a result of the
discontinuation of most of the businesses within the Energy Marketing
Operations, this segment has been deleted. In addition, due to the sale of Cove
Point LNG and Columbia Electric Corporation (Columbia Electric) and the pending
sale of the propane business, the Power Generation, LNG and Other Operations
segment has been renamed Other Products and Services.

Transmission and Storage Operations
Columbia's two interstate pipeline subsidiaries, Columbia Gas Transmission
Corporation (Columbia Transmission) and Columbia Gulf Transmission Company
(Columbia Gulf), own a pipeline network of approximately 15,880 miles 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. Together, Columbia Transmission
and Columbia Gulf serve customers in 15 northeastern, mid-Atlantic, mid-western,
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. The
transmission and storage subsidiaries are engaged in several projects, the
largest of which is the proposed 442-mile Millennium Pipeline Project in which
Columbia Transmission is participating. As proposed, the project will transport
approximately 700,000 Dekatherm (Dth) of natural gas per day from the Lake Erie
region to eastern markets. This project is currently awaiting approval by the
Federal Energy Regulatory Commission (FERC). In early November 2000, Columbia
Gulf completed the largest expansion of its mainline facility, Mainline '99. At
completion, total capacity was increased by approximately 315,000 Dth/day and
certificated capacity was increased to approximately 2.2 billion cubic feet
(Bcf) per day. Appeals challenging the FERC's authorization of the project are
currently pending review by the United States Court of Appeals.

Columbia Transmission and Columbia Gulf provide an array of competitively priced
natural gas transportation and storage services for local distribution companies
(LDCs) and industrial and commercial customers who contract directly with
producers or marketers for their gas supplies. See Item 7, page 16 for
additional information.

Distribution Operations
Columbia's five distribution subsidiaries provide natural gas service to nearly
2.1 million residential, commercial and industrial customers in Ohio,
Pennsylvania, Virginia, Kentucky and Maryland. Approximately 32,796 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 only. This
ability to choose a supplier was previously limited to larger commercial and
industrial customers. See Item 7, page 20 for additional information.

Exploration and Production Operations
Columbia Energy Resources, Inc. (Columbia Resources) is an exploration and
production subsidiary that explores for, develops, gathers and produces natural
gas and oil in Appalachia and Canada. As of December 31, 2000, Columbia
Resources had net proven oil and gas reserve holdings of 1.1 trillion cubic feet
equivalent and owned and operated 6,235 miles of gathering pipelines. See Item
7, page 23 for additional information.

Other Products and Services
Columbia Transmission Communications Corporation (Transcom), a wholly-owned
subsidiary of Columbia, is building a dark-fiber optics telecommunications
network primarily along pipeline rights-of-way between New


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

York and Washington, D.C. The route covers 260 miles and provides access to 16
million people in the busiest telecommunications corridor in the United States.
Columbia currently is pursuing strategic alternatives for its telecommunications
network in order to focus its resources on its core businesses.

Columbia's subsidiary, Columbia Service Partners, is engaged in the business of
providing energy-related services to customers of LDCs affiliated with Columbia
and to nonaffiliated customers that are served by Columbia's interstate natural
gas transmission companies.

For additional discussion of Columbia's business segments, including financial
information for the last three fiscal years, see Item 7, pages 11 through 26 and
Note 17 on pages 50 through 52 of Item 8.

Competition
The regulatory frameworks applicable to Columbia's rate-regulated operations, at
both the state and federal levels, are undergoing fundamental changes. These
changes have impacted and will continue to have an impact on Columbia's
operations, structure and profitability. At the same time, competition within
the gas industry will create opportunities to compete for new customers and
revenues. Management continually seeks new ways to be more competitive and
profitable in this changing environment, including partnering on energy projects
with major industrial customers, providing its gas customers with increased
customer choice for new products and services, acquiring companies that will
provide improved economies of scale and efficiencies and developing new
energy-related products for residential, commercial and industrial customers.

Open access to natural gas supplies over interstate pipelines and the
deregulation of the commodity price of gas has led to tremendous change in the
energy markets, which continue to evolve. During the past few years, LDC
customers and marketers began to purchase gas directly from producers and an
open competitive market for gas supplies emerged. This separation or
"unbundling" of the transportation and other services offered by pipelines and
LDCs allows customers to select the service they want independent from the
purchase of the commodity. Columbia's gas 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 natural gas markets are evolving, the markets for competing energy
sources are also changing.

Forward Looking Statements
The foregoing discussion and Item 3 contain "forward-looking statements," within
the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended. Investors and
prospective investors should understand that many 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. These forward-looking statements include, but are not limited to,
statements concerning Columbia's plans, dispositions, objectives, expected
performance, expenditures and recovery of expenditures through rates, stated on
either a consolidated or segment basis, and 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, increased competition in deregulated energy markets, weather,
fluctuations in supply and demand for energy commodities, successful
consummation of dispositions, growth opportunities for Columbia's businesses,
dealings with third parties over whom Columbia has no control, the regulatory
process, regulatory and legislative changes as well as changes in general
economic, capital and commodity market conditions, counter-party credit risk,
many of which are beyond the control of Columbia. In addition, the relative
contributions to profitability by each segment, and the assumptions underlying
the forward-looking statements relating thereto, may change over time.


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

Other Relevant Business Information
Columbia customer base is broadly diversified, with no single customer
accounting for a significant portion of revenues.

As of January 31, 2001, Columbia had 8,001 full-time employees of which 1,478
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 17, 21 and 25, and in Item 8, Note 14I on
page 48.


                                       5

<PAGE>   6
ITEM 2.  PROPERTIES


Information relating to properties of subsidiary companies is detailed below and
on page 7 and page 36 of Item 8 under Note 1E. Assets under lien and other
guarantees are described on page 48 in Note 14D 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, 2000

<TABLE>
<CAPTION>
                              Developed Acreage            Undeveloped Acreage
                        --------------------------      ------------------------
                          Gross            Net           Gross            Net
                        ---------        ---------      ---------      ---------
<S>                     <C>              <C>            <C>            <C>
United States           2,194,419        2,063,250      1,149,003      1,015,140
Canada...............       3,524           1,626       1,435,544        775,586
                        ---------        ---------      ---------      ---------
Total................   2,197,943        2,064,876      2,584,547      1,790,726
                        =========        =========      =========      =========
</TABLE>


Net Wells Completed - 12 Months Ended December 31,

<TABLE>
<CAPTION>
                            Exploratory            Development               Total
                         -------------------    ------------------    ------------------
                         Productive     Dry     Productive     Dry    Productive     Dry
                         ----------     ---     ----------     ---    ----------     ---

United States........

<S>                         <C>          <C>      <C>          <C>        <C>        <C>
     2000............       3            1        206          11         209        12
     1999............       3            1        193          37         196        38
     1998............       5            1        136          32         141        33
Canada...............
     2000............       2            3          2           4           4         7
     1999............       -            1          1           2           1         3
     1998............       -            1          -           1           -         2
</TABLE>


Productive and Drilling Wells - At December 31, 2000

<TABLE>
<CAPTION>
                                          Production Wells
                               ---------------------------------
                                    Gross                Net                Wells Drilling
                               --------------       -------------          -----------------
                               Gas        Oil       Gas       Oil           Gross       Net
                               ---        ---       ------   -----          -----       ---

<S>                            <C>        <C>       <C>        <C>             <C>        <C>
United States........          7,962(a)   105       7,483      66              37         33
Canada...............             26        6          13       4               6          4
                               ------   -----       -----  ------          ------       ----
Total................          7,988      111       7,496      70              43         37
                               =====    =====       =====  ======          ======       ====
</TABLE>


 (a) Includes 604 multiple completion gas wells, all of which are included as
     single wells in the table. Also includes 1 gross productive horizontal
     well.


                                       6

<PAGE>   7
ITEM 2.  PROPERTIES (Continued)


            GAS PROPERTIES OF SUBSIDIARIES - AS OF DECEMBER 31, 2000


<TABLE>
<CAPTION>
                                                 Underground Storage                     Miles of Pipeline
                                         -------------------------------      -------------------------------------------
                                                                              Gathering
                 Subsidiaries             State        Acreage     Wells      and Storage    Transmission    Distribution
<S>                                       <C>       <C>            <C>        <C>            <C>             <C>
Columbia Gas of Kentucky, Inc.            KY              -            -          -              -            2,463
Columbia Gas of Maryland, Inc.            MD              -            -          -              -              606
Columbia Gas of Ohio, Inc.                OH              -            -          -              -           18,622
Columbia Gas of Pennsylvania, Inc.        PA          3,300            8          4              -            7,010
Columbia Gas of Virginia, Inc.            VA              -            -          -              -            4,095
Columbia Gas Transmission Corporation     DE              -            -          -              3                -
                                          KY              -            -          -            713                -
                                          MD            945            -          -            179                -
                                          NJ              -            -          -             69                -
                                          NY         26,286          144         30            321                -
                                          NC              -            -          -              1                -
                                          OH        486,954        2,477        815          3,921                -
                                          PA         64,532          221         72          1,856                -
                                          VA              -            -          -          1,117                -
                                          WV        285,277          793        272          2,397                -
Columbia Gulf Transmission Company        KY              -            -          -            716                -
                                          LA              -            -          -          2,016                -
                                          MS              -            -          -            659                -
                                          TN              -            -          -            556                -
                                          TX              -            -          -            159                -
                                          WY              -            -          -             10                -
Columbia Energy Resources, Inc.           KY              -            -      2,332              -                -
                                          MI              -            -          6              -                -
                                          NY              -            -        136              -                -
                                          OH              -            -        128              -                -
                                          PA              -            -         38              -                -
                                          TN              -            -         45              -                -
                                          VA              -            -        439              -                -
                                          WV              -            -      3,111              -                -
Columbia Pipeline Company                 LA              -            -          3              -                -
                                                    -------        -----      -----         ------           ------
Total                                               867,294        3,643      7,431         14,693           32,796
                                                    =======        =====      =====         ======           ======
</TABLE>



            GAS PROPERTIES OF SUBSIDIARIES - AS OF DECEMBER 31, 2000


<TABLE>
<CAPTION>
                                            Compressor Stations
                                                Installed
                                        ---------------------------
                 Subsidiaries           Number         Capacity (hp)

<S>                                      <C>           <C>
Columbia Gas of Kentucky, Inc.             -                   -
Columbia Gas of Maryland, Inc.             -                   -
Columbia Gas of Ohio, Inc.                 -                   -
Columbia Gas of Pennsylvania, Inc.         1                 800
Columbia Gas of Virginia, Inc.             -                   -
Columbia Gas Transmission Corporation      -                   -
                                           5               9,270
                                           1              12,000
                                           -                   -
                                           3               3,880
                                           1               1,200
                                          25             103,187
                                          23              66,194
                                          10              79,330
                                          39             313,564
Columbia Gulf Transmission Company         2              70,000
                                           6             195,500
                                           3             131,500
                                           2              86,200
                                           -                   -
                                           -                   -
Columbia Energy Resources, Inc.           21              40,788
                                           -                   -
                                           3                 860
                                           3                 400
                                           -                   -
                                           3                 925
                                           1               1,000
                                          22               1,999
Columbia Pipeline Company                  -                   -
                                         ---           ---------
Total                                    174           1,118,597
                                         ===           =========
</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 Transmission's
         property has been pledged to Columbia as security for First Mortgage
         Bonds issued by Columbia Transmission to Columbia.




                                       7
<PAGE>   8
ITEM 3.  LEGAL PROCEEDINGS


   A. Canada Southern Petroleum Ltd. v. Columbia Gas Development of Canada Ltd.
      C.A. No. 9001-03466, Court of Queen's Bench, Alberta, Canada, filed March
      7, 1990. The plaintiffs assert, 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 plaintiffs seek, among
      other remedies, the return of the defendants' interests in the Kotaneelee
      field to the plaintiffs, a declaration that such interests are held in
      trust for the plaintiffs and an order requiring the defendants to promptly
      market Kotaneelee gas or assessing damages.

      In November 1993, the plaintiffs amended their 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 plaintiffs'
      acknowledgment that approximately $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. Following multiple lengthy adjournments, the parties have concluded
      presenting their witnesses and evidence and have made their post-trial
      arguments. The parties are awaiting the courts ruling. Management
      continues to believe that its defenses are meritorious, and that the risk
      of any material liability to Columbia is de minimis.

      Pursuant to an Indemnification Agreement regarding the Kotaneelee
      Litigation entered into when Columbia Canada was sold to Anderson,
      Columbia agreed to indemnify and hold Anderson harmless for losses due to
      this litigation arising out of actions occurring prior to December 31,
      1991. An escrow account provides security for the indemnification
      obligation and is funded by a letter of credit with a face amount of
      approximately $35,835,000 (Cdn).

   B. Columbia Gas Transmission Corp. v. Consolidation Coal Co., et al.,
      C.A. No. 99-2071 W.D. Pa. On December 21, 1999, Columbia
      Transmission filed a complaint against Consolidation Coal Co. and McElroy
      Coal Co. (collectively, Consol), seeking declaratory and permanent
      injunctive relief enjoining Consol from pursuing its current plan to
      conduct longwall mining through Columbia Transmission's Victory Storage
      Field (Victory) in northern West Virginia. The complaint was served on
      April 10, 2000. Consol's current plans to longwall mine through the
      Victory would destroy certain infrastructure of Victory, including all of
      Columbia Transmission's storage wells in the path of the mining. The
      parties are holding discussions concerning resolution of this matter. On
      December 8, 2000, the court denied Consol's Motion to Dismiss for
      protective order, and discovery by the parties has been initiated.

   D. Transcom. On March 17, April 11 and April 21, 2000, one of Columbia's
      subsidiaries, Transcom received directives from the Philadelphia District
      of the U.S. Army Corps of Engineers (Philadelphia District) and an
      administrative order from The Pennsylvania Department of Environmental
      Protection (PA DEP) addressing alleged violations of federal and state
      laws resulting from construction activities associated with Transcom's
      laying fiber optic cable along portions of a route between Washington,
      D.C. and New York City. The order and directives required Transcom to
      largely cease construction activities. On September 18, 2000, Transcom
      entered into a voluntary settlement agreement with the Philadelphia
      District under which Transcom contributed $1.2 million to the Pennsylvania
      chapter of the Nature Conservancy and the Philadelphia District lifted its
      directives. As a result of the voluntary agreement with the Philadelphia
      District and communications with the PA DEP, the Maryland Department of
      the Environment and the Baltimore District of the U.S. Army Corps of
      Engineers, work in Pennsylvania and Maryland is now ongoing. Transcom
      cannot predict the nature or amount of total remedies that may be sought
      in connection with the foregoing construction activities.

   E. United States of America ex rel. Jack J. Grynberg v Columbia Gas
      Transmission Corp. et. al., CA No. 97-2091-K, E.D. La. The plaintiff filed
      a complaint under the False Claims Act, on behalf of the United States of
      America, against approximately seventy pipelines including Columbia Gulf.
      The plaintiff claimed that the defendants had submitted false royalty
      reports to the government (or caused others to do so) by mismeasuring the
      volume and heating content of natural gas produced on Federal land and
      Indian lands. Plaintiff's original complaint was dismissed without
      prejudice for misjoinder of parties and for failing to plead fraud with
      specificity. The plaintiff then filed over sixty-five new False Claims Act
      complaints against over 330 defendants in numerous Federal courts. One of
      those complaints was filed in the Federal District Court for the Eastern
      District of


                                       8
<PAGE>   9
      Louisiana against Columbia and thirteen affiliated entities. Plaintiff's
      second complaint repeats the mismeasurement claims previously made and
      adds valuation claims alleging that the defendants have undervalued
      natural gas for royalty purposes in various ways, including sales to
      affiliated entities at artificially low prices. Most of the Grynberg cases
      were transferred to Federal court in Wyoming, in 1999. In December, 1999,
      the Columbia defendants filed a motion to dismiss plaintiff's second
      complaint primarily based on a failure to plead fraud with specificity. A
      hearing was held on the motion in March, 2000 but the court has not yet
      ruled on.

   F. Quinque Operating Co. et al v. Gas Pipelines et al., Case No. 99 C 30,
      Stevens County, Kansas Plaintiff filed an amended complaint in Stevens
      County, Kansas state court against over 200 natural gas measurers, mostly
      natural gas pipelines, including Columbia and fourteen affiliated
      entities. The allegations in Quinque are similar to those made in Grynbeg;
      however, Quinque broadens the claims to cover all oil and gas leases
      (other than the Federal and Indian leases that are the subject of
      Grynberg). Qunique asserts a breach of contract claim, negligent or
      intentional misrepresentation, civil conspiracy, common carrier liability,
      conversion, violation of a variety of Kansas statutes and other common law
      causes of action. Quinque purports to be a nationwide class action filed
      on behalf of all similarly situated gas producers, royalty owners,
      overriding royalty owners, working interest owners and certain state
      taxing authorities. The defendant had previously remanded the case to
      Federal court. On January 12, 2001, the Federal court remanded the case to
      state court.

   G. Vivian K. Kershaw et al. v. Columbia Natural Resources, Inc., et al., CA
      No. 00-CV-246C(H), W.D.N.Y. In February, 2000, plaintiff filed a complaint
      in New York state court against Columbia Natural Resources (CNR) and
      Columbia Transmission. The complaint alleges that Kershaw owns an interest
      in an oil and gas lease in New York and that the defendants have underpaid
      royalties on those leases by, among other things, failing to base
      royalties on the price at which natural gas is sold to the end user and by
      improperly deducting post-production costs. The complaint also seeks class
      action status on behalf of all royalty owners in oil and gas leases
      operated by CNR. Plaintiff seeks the alleged royalty underpayments and
      punitive damages. Columbia removed the case to Federal court in March,
      2000. The Federal court has now remanded Kershaw back to New York State
      court.

   H. Anthony Gonzalez, et al. v. National Propane Corporation, et al. Case No.
      97 L 15857 Circuit Court of Cook County, Illinois On December 11, 1997,
      Plaintiffs Anthony Gonzalez, Helen Pieczynski, as Special Administrator of
      the Estate of Edmund Pieczynski, deceased, Michael Brown and Stephen
      Pieczynski filed a multiple-count complaint for personal injuries in the
      Circuit Court of Cook County, Illinois against National Propane
      Corporation and the Estate of Edmund Pieczynski sounding in strict tort
      liability and negligence. Plaintiff's complaint arises from an explosion
      and fire which occurred in a Wisconsin vacation cottage in 1997. National
      Propane, L.P. filed a third-party complaint for contribution against
      Natural Gas Odorizing and Phillips Petroleum Company. Written discovery
      has been completed and the parties are conducting oral discovery of the
      fact witnesses. There has been no trial date set in the matter, and the
      next court date is June 27, 2001, at which time further scheduling of
      discovery will occur.

   C. McElroy Coal Company v. Columbia Gas Transmission Corporation, No. 5-01 CV
      18 U.S. Dist. Ct. N.D. WV, On February 12, 2001, McElroy Coal Company
      (McElroy), an affiliate of Consolidation Coal Co., filed a complaint
      against Columbia Transmission in federal court in Wheeling, West Virginia.
      The West Virginia complaint seeks declaratory and injunctive relief as to
      McElroy's alleged right to mine coal within Victory and Columbia
      Transmission's obligation to take all necessary measures to permit McElroy
      to longwall mine. The complaint also seeks compensation for the inverse
      condemnation of any coal that cannot be mined due to Columbia
      Transmission's Victory operations. Except for the claim of inverse
      condemnation, McElroy's West Virginia complaint appears to be virtually
      identical to Consolidation Coal Co.'s counterclaim to Columbia
      Transmission's federal court action in Pennsylvania. We are currently
      evaluating McElroy's West Virginia complaint and Columbia Transmission's
      potential responses.


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

NiSource is the holder of record of all the outstanding common equity securities
of Columbia.


                                       9
<PAGE>   10

ITEM 6. SELECTED FINANCIAL DATA

<TABLE>
<CAPTION>
                             SELECTED FINANCIAL DATA
                     Columbia Energy Group and Subsidiaries

($ in millions)                                                        2000       1999       1998         1997        1996
-----------------------------------------------------------------------------------------------------------------------------

INCOME STATEMENT DATA($)
<S>                                                                 <C>         <C>         <C>          <C>         <C>
   Net revenues                                                     1,936.5     1,908.0     1,823.9      1,863.4     1,826.4
   Earnings (Loss) before discontinued operations,
      extraordinary item and accounting changes                       294.6       387.8       308.9        276.3       214.5
   Earnings (Loss) before extraordinary item
      and accounting changes                                          133.7       249.2       269.2        273.3       221.6
   Earnings (Loss) on common stock                                    133.7       249.2       269.2        273.3       221.6

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

BALANCE SHEET DATA($)
   Capitalization
      Common stock equity                                           2,035.9     2,064.0     2,005.3      1,790.7     1,553.6
      Preferred stock                                                    --          --          --           --          --
      Long-term debt                                                1,639.1     1,639.3     2,002.8      2,003.0     2,003.8
      Short-term debt                                                 521.0       465.5         N/A          N/A         N/A
      Current maturities of long-term debt                              0.2       311.1         0.2          0.4         0.4
      Total                                                         4,196.2     4,479.9     4,008.3      3,794.1     3,557.8
   Total assets                                                     7,626.2     7,037.3     6,495.2      6,236.3     5,875.8

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

OTHER FINANCIAL DATA
   Capitalization ratio(%)(including current maturities *):
      Common stock equity                                              48.5        46.1        50.0         47.2        43.7
      Preferred stock                                                    --          --          --           --          --
      Debt                                                             51.5        53.9        50.0         52.8        56.3
   Capital expenditures($)                                            498.3       558.1       460.7        553.3       308.7
   Net cash from operations($)                                        558.0       536.7       686.1        486.8       452.3
   Return on average common equity before discontinued
      operations, extraordinary item and accounting changes(%)         14.4        19.1        16.3         16.5        16.1

-----------------------------------------------------------------------------------------------------------------------------
</TABLE>

N/A - Not applicable


*     Short-term borrowings were used in 1999 and 2000 to finance acquisitions
      and to fund Columbia's stock repurchase program. Inclusion of the
      short-term debt in 1999 and 2000 makes those historical ratios more
      meaningful.





                                       10
<PAGE>   11
ITEM 7.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
          RESULTS OF OPERATIONS


Index                                                                   Page
Consolidated Review....................................................   11
Liquidity and Capital Resources........................................   13
Transmission and Storage Operations....................................   16
Distribution Operations................................................   20
Exploration and Production Operations..................................   23
Other Products and Services............................................   25

The Management's Discussion and Analysis of Financial Condition and Results of
Operations, including statements regarding market risk sensitive instruments,
contains "forward-looking statements" within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange
Act of 1934, as amended. Investors and prospective investors should understand
that many 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. These forward-looking statements
include, but are not limited to, statements concerning Columbia's plans,
dispositions, objectives, expected performance, expenditures and recovery of
expenditures through rates, stated on either a consolidated or segment basis,
underlying assumptions and statements that are other than 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 objective and expected performance is
subject to a wide range of risks and can be adversely affected by, among other
things, increased competition in deregulated energy markets, weather conditions,
fluctuations in energy-related commodity prices, service territories, successful
consummation of dispositions, growth opportunities for Columbia's regulated and
non-regulated businesses, dealings with third parties over whom Columbia has no
control, the regulatory process, regulatory and legislative changes, changes in
general economic, capital and commodity market conditions and counter-party
credit risk, many of which are beyond the control of Columbia. In addition, the
relative contributions to profitability by each segment, and the assumptions
underlying the forward-looking statements relating thereto, may change over
time.

Merger Agreement
On February 28, 2000, Columbia and NiSource entered into an Agreement and Plan
of Merger, dated as of February 27, 2000, and subsequently amended and restated
on March 31, 2000 (Merger Agreement). In early June 2000, shareholders of both
companies approved the merger between NiSource and Columbia.

On November 1, 2000, NiSource completed the acquisition of Columbia for an
aggregate consideration of approximately $6 billion, with 30% of the
consideration paid in common stock and 70% of the consideration paid in cash and
Stock Appreciation Income Linked Securities(SM), referred to as SAILS(SM), which
are units consisting of zero coupon debt security coupled with a forward equity
contract in NiSource shares. NiSource also assumed approximately $2 billion in
Columbia debt. As provided for in the Merger Agreement, NiSource organized a new
company that serves as the holding company for Columbia and its other
subsidiaries.

                               CONSOLIDATED REVIEW

Columbia's income from continuing operations for 2000 was $294.6 million, a
decrease of $93.2 million from 1999. The decrease primarily reflected
approximately $160 million after-tax in merger-related expenditures in 2000,
partially offset by the sale of Columbia Electric and the Cove Point LNG
facilities, which sales improved after-tax income by $86.4 million and $58.9
million, respectively. Also improving 2000 results was 9% colder weather
compared to 1999. In 1999, a settlement of a co-generation power purchase
contract increased after-tax income by $49 million and a producer contract
settlement improved income $20.6 million after-tax.

Discontinued operations, which include the propane, petroleum and mass marketing
businesses of Columbia Energy Services, Inc. (Columbia Energy Services),
reflected an after-tax loss of $160.9 million in 2000. Taking into account
income from continuing operations and the loss from discontinued operations,
Columbia reported net income of $133.7 million in 2000, versus $249.2 million in
the prior year.

Income from continuing operations for 1999 of $387.8 million increased $78.9
million over 1998, essentially due to a $49 million after-tax gain recorded in
connection with the termination of a co-generation power purchase contract,


                                       11
<PAGE>   12
ITEM 7.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
          RESULTS OF OPERATIONS (continued)


a $20.6 million after-tax gain related to the final producer contract, an
after-tax gain of $7.8 million on the sale of Columbia's interests in the
Trailblazer pipeline system and a reduction in tax expense for the realization
of certain tax benefits that increased net income by $6.9 million. Tempering
these increases was a $16.5 million improvement recorded in 1998 for a
settlement gain related to post-retirement benefit costs.

The after-tax loss on discontinued operations was $138.6 million in 1999
compared to $39.7 million in 1998. Income from continuing operations together
with the loss from discontinued operations resulted in reported net income in
1999 of $249.2 million, a decrease of $20 million from 1998.

Net Revenues
Total net revenues (revenues less associated product purchased costs) of
$1,936.5 million for 2000 reflected an increase of $28.5 million over 1999
primarily due to colder weather during the fourth quarter, an improvement in
transportation revenue and increased natural gas prices and production for
Columbia Resources' operations. Tempering these improvements was the 1999 gain
recorded on the termination of a co-generation power purchase contract and a
decline in off-system sales.

For 1999, total net revenues of $1,908 million reflected an increase of $84.1
million over 1998, primarily due to the effect of colder weather in 1999 on gas
sales for the distribution segment and higher revenues from transportation
services in the exploration and production. Also improving revenues in 1999 was
the gain recorded for the termination of a co-generation power purchase
contract. Tempering this increase were reduced net revenues associated with the
net effect of several Columbia Gas of Ohio, Inc. (Columbia of Ohio) regulatory
settlements.

Expenses
Total operating expenses for 2000 were $1,518.2 million, an increase of $305.4
million over 1999, reflecting higher expenses in 2000 attributable to
merger-related activities and employee-related costs for Columbia Electric's
projects. Tempering this increase were reduced labor and benefits costs as a
result of implementing the Voluntary Incentive Retirement Program (VIRP) and the
positive impact of the 1997 Columbia of Ohio regulatory settlement.

Total operating expenses of $1,212.8 million for 1999 decreased $20.5 million
compared to 1998. The decrease was primarily due to the settlement of
producer-related litigation in 1999, which reduced operating expenses in that
year by $31.7 million and a decrease in depreciation and depletion expense due
to the impact of Columbia of Ohio's 1999 regulatory settlement. These decreases
were partially offset by higher operation and maintenance expense in 1999 due to
start-up costs related to new businesses.

Other Income (Deductions)

<TABLE>
<CAPTION>
Twelve Months Ended December 31, (in millions)            2000           1999         1998
-------------------------------------------------------------------------------------------
<S>                                                 <C>             <C>         <C>
 Interest income and other, net                     $    236.3      $    34.9   $     14.7
 Interest expense and related charges                   (169.6)        (164.2)      (144.2)
-------------------------------------------------------------------------------------------
 TOTAL OTHER INCOME (DEDUCTIONS)                    $     66.7      $  (129.3)  $  (129.5)
-------------------------------------------------------------------------------------------
</TABLE>

Other income (deductions) improved income by $66.7 million in 2000 compared to a
reduction of $129.3 million in 1999. Interest income and other, net, of $236.3
million was $201.4 million greater than in the year earlier, due largely to the
gain from the sale of Columbia Electric and Cove Point facilities in 2000.
Tempering this increase was the improvement in 1999 from the sale of Columbia's
interests in a pipeline partnership for $12.1 million and from the sale of coal
properties for $2.9 million. Interest expense and related charges of $169.6
million increased $5.4 million due largely to higher short-term borrowings to
finance acquisitions and fund Columbia's stock repurchase program, as discussed
below, tempered by lower interest on contingent taxes.

For 1999, other income (deductions) reduced income by $129.3 million, relatively
unchanged from 1998. Interest income and other, net of $34.9 million increased
$20.2 million when compared to 1998, due largely to the gain on a pipeline
partnership sale and the sale of coal properties. Interest expense and related
charges of $164.2 million in 1999 increased $20 million over 1998, primarily
reflecting an increase in interest expense related to a 1991-1994 settlement of
contingent taxes and higher interest costs due to additional borrowing.


                                       12
<PAGE>   13
ITEM 7.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
          RESULTS OF OPERATIONS (continued)


Income Taxes
Income tax expense in 2000 totaled $190.4 million, an increase of $12.3 million
over 1999, primarily due to the utilization of certain tax benefits and state
tax planning initiatives during 1999. Tempering this increase was the impact of
lower pre-tax income.

Income tax expense of $178.1 million for 1999 increased $25.9 million over the
year earlier, primarily reflecting higher pre-tax income. Income benefited as a
result of utilizing state tax planning initiatives during 1999 and 1998.

Discontinued Operations
Discontinued operations reflected an after-tax loss of $160.9 million in 2000
compared to an after-tax loss of $138.6 million in 1999. The increased loss was
primarily related to an additional loss recorded for the proposed sale of the
propane operations.

During 2000, Columbia undertook an evaluation of the appropriateness of
remaining in certain businesses given the rapidly changing energy industry and
the pending merger with NiSource. During the course of this assessment, it was
determined to essentially exit the energy marketing operations, which includes
the propane, petroleum and Columbia Energy Services' mass marketing business, as
discussed below. In accordance with generally accepted accounting principles,
the results from these businesses are now reported as discontinued operations.

In the fourth quarter of 1999, Columbia Energy Services, a wholly-owned
subsidiary of Columbia, sold its wholesale and trading operations to Enron North
America Corporation. In late 1999, Columbia Energy Services also decided to exit
its major accounts business.

In May 2000, Columbia Energy Services sold its internet-based energy marketing
operation, Energy.com. Also in May 2000, Columbia announced that it was in the
process of preparing its propane and petroleum businesses for sale. In early
2001, NiSource announced that Columbia Propane Corporation had signed a
definitive agreement for approximately $208 million, including $53 million of
partnership common units. The closing is expected to occur in the second quarter
of 2001.

In the third quarter of 2000, Columbia sold its retail energy mass marketing
business to The New Power Company, a national residential and small business
energy provider.

Late in 2000, Columbia sold its interest in Columbia Electric's four power
generation plants to a partnership between Delta Power Company and John Hancock
Life Insurance Company and the remainder of Columbia Electric to Orion Power.
The gain on the sale of these assets resulted in an improvement to consolidated
net income of approximately $86 million.

                         LIQUIDITY AND CAPITAL RESOURCES

A significant portion of Columbia's operations is 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, is 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.

With the significant increase in gas prices experienced over the last few months
of 2000 and early 2001, gas purchased for resale by Columbia's distribution
subsidiaries has resulted in an under recovery of these costs given the current
rates in effect. However, the recovery of these higher costs are provided for
under the current regulatory process. Management believes that this recovery
mechanism will continue to provide full recovery of gas costs.

Net cash from continuing operations for the year ended December 31, 2000 was
$545.2 million, a $237.8 million decrease from the same period in 1999. The
decrease was primarily due to the impact of higher gas prices on gas purchased
for resale and merger-related and restructuring activities, tempered by increase
cash receipts due to the impact of colder weather.

Columbia satisfies its liquidity requirements primarily through internally
generated funds and from the sale of commercial paper, which is supported by two
unsecured bank revolving credit facilities (Credit Facilities). On October 11,
2000, the Credit Facilities were amended and restated, and reduced from the
previous level of $1.35 billion to $900 million. The previous $450 million
364-day facility was increased to $850 million, and is scheduled


                                       13
<PAGE>   14
ITEM 7.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
          RESULTS OF OPERATIONS (continued)


to expire in October 2001. The prior $900 million five-year facility was
decreased to $50 million, shortened to a two-year facility expiring in October
2002, and will be solely used to support the issuance of letters of credit.

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. In addition, the Credit Facilities have a utilization fee if
borrowings exceed a certain level.

As of December 31, 2000, Columbia had approximately $124.2 million of letters of
credit issued, of which approximately $14.6 million were issued under the Credit
Facilities, and $521 million of commercial paper was outstanding.

NiSource is in the process of arranging a new $2.5 billion revolving credit
facility with a syndicate of banks for future working capital requirements. The
new facility will refinance and consolidate essentially all of NiSource's
existing short-term credit facilities, including Columbia's as discussed above,
into one credit facility, through NiSource's financing subsidiary. Management
expects to have this new facility in place by the end of the first quarter of
2001.

In 1998, Columbia entered into several fixed-to-floating interest-rate swap
agreements to modify the interest characteristics of $300 million of its
outstanding long-term debt. As a result of these transactions, that portion of
Columbia's long-term debt is now subject to fluctuations in interest rates. This
allows Columbia to benefit from a lower interest rate environment. In order to
maintain a balance between fixed and floating interest rates, Columbia is
targeting average annual floating rate debt exposure for 10 to 20% of its
outstanding long-term debt.

Columbia has an effective shelf registration statement on file with the
Securities and Exchange Commission (SEC) for the issuance of up to $1 billion in
aggregate of debentures, common stock or preferred stock in one or more series.
Currently, Columbia has $750 million available under the shelf registration.

Management believes that its sources of funding are sufficient to meet the
short-term and long-term liquidity needs of Columbia.

Common Stock Repurchase Program
During 1999, Columbia's Board of Directors (Columbia's Board) authorized the
repurchase of up to $500 million of Columbia's common stock through July 14,
2000, in the open market. During that period, a total of 4,368,300 common shares
has been repurchased under this program at a cost of $249.1 million. Purchased
shares were held in treasury and have since been retired as a result of the
acquisition of Columbia by NiSource.

Capital Expenditures
The table below reflects actual capital expenditures by segment for 2000 and
1999 and an estimate for year 2001:

<TABLE>
<CAPTION>
(in millions)                          2001           2000           1999
--------------------------------------------------------------------------------
<S>                                  <C>            <C>             <C>
  Transmission and Storage           $132.0         $128.9          $183.4
  Distribution                        113.0          139.6           145.5
  Exploration and Production          132.0          128.9           166.5
  Other Products and Services           2.0           96.0            57.3
  Corporate                              --            4.9             5.4
--------------------------------------------------------------------------------
  Total                              $379.0         $498.3          $558.1
--------------------------------------------------------------------------------
</TABLE>
For 2000, capital expenditures were $498.3 million, a decrease of $59.8 million
from 1999. The 2000 program included approximately $56 million for extending
service to new areas and $60 million for replacement and betterment projects for
the distribution segment. The largest portion of the 2000 program for the
transmission and storage segment was to ensure the safety and reliability of the
pipelines and for market expansion activities as well as new business
initiatives. The distribution subsidiaries' program includes investments to
extend service to new areas and develop future markets, as well as expenditures
ensuring safe, reliable and improved service. The exploration and production
segment's 2000 program included amounts for its expanded drilling program and
acquisitions.

For 2001, Columbia's estimated capital expenditure program of $379 million is
$119.3 million lower than the 2000 program which reflects Columbia's effort to
divest assets and maintain operations that are in line with its core strategy.

Market Risk Exposure
Subsidiaries in Columbia's exploration and production segment are exposed to
market risk due primarily to fluctuations in commodity prices. NiSource's risk
management policy permits the use of certain financial instruments to manage its
market risk including futures, swaps and options. Risk management is defined as
the process by which the organization ensures that the risks to which it desires
to be exposed to achieve its primary


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


business objectives. Columbia Resources utilizes financial instruments to fix
prices for a portion of its future production volumes, which are hedged in the
marketplace through a third party.


NiSource's senior management takes an active role in the risk management process
and has developed policies and procedures that require specific administrative
and business functions to assist in the identification, assessment and control
of various risks. In recognition of the increasingly varied and complex nature
of the energy business, NiSource's risk management policies and procedures
continue to evolve and are subject to ongoing review and modification.

As noted, Columbia also utilizes fixed-to-floating interest rate swap agreements
to modify the interest characteristics of a portion of its outstanding long-term
debt. As a result of these transactions, $300 million of Columbia's long-term
debt is now subject to fluctuations in interest rates.

Voluntary Workforce Reduction Programs
As a result of Columbia's ongoing review of its various business units, the
utilization of improved technologies and process improvement initiatives,
management has identified a number of ways of working more efficiently. As
discussed below, Columbia implemented the VIRP at various times during 1999 and
2000 for active employees who were age fifty and above with at least five years
of service.

In September 1999, Columbia Transmission announced a VIRP that provided a
retirement incentive for eligible employees as of March 1, 2000. Approximately
486 of its 600 eligible employees elected early retirement under this program
with the majority of the retirements occurring in the first quarter of 2000.

In February 2000, the five distribution subsidiaries and Columbia Energy Group
Service Corporation (Service Corp.) announced the introduction of a VIRP for 879
eligible employees as of June 1, 2000. The acceptance period ended on April 30,
2000, with 679 employees accepting the VIRP. The majority of the retirements
occurred on June 1, 2000.

In September 2000, Columbia announced that employees of the five distribution
subsidiaries and Service Corp., whom were not eligible for the February 2000
program, as well as the employees of Columbia Resources, would be offered a VIRP
as of January 1, 2001. Approximately 172 of its 400 eligible employees elected
early retirement. The actual retirement date for those employees electing the
VIRP will be based on the specific business needs of the business units.

Following the announcement of the merger with NiSource, another VIRP was offered
to certain employees not eligible for the earlier VIRPs. The acceptance period
ended on December 22, 2000, with 64 employees accepting the VIRP. The majority
of the retirements occurred on January 1, 2001.

Presentation of Segment Information
Columbia revised its presentation of its primary business segment information
beginning with the reporting of second quarter 2000 results. As a result of the
discontinuation of most of the businesses within the Energy Marketing
Operations, this segment has been deleted. In addition, due to the sale of Cove
Point LNG, the Power Generation, LNG and Other Operations segment has been
renamed Other Products and Services. The results for Columbia Service Partners
Inc., which provides energy-related services to primarily residential customers,
were previously in Energy Marketing Operations. These operations were
reclassified to Other Products and Services.


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


                       TRANSMISSION AND STORAGE OPERATIONS

Columbia's transmission and storage segment consists of the operations of
Columbia Transmission, Columbia Gulf and Columbia Pipeline Corporation. Together
they own a pipeline network of approximately 15,880 miles extending from
offshore in the Gulf of Mexico to Lake Erie, New York and the eastern seaboard
serving 15 northeastern, mid-Atlantic, mid-western and southern states, as well
as the District of Columbia. In addition, Columbia Transmission operates one of
the nation's largest underground natural gas storage systems.

Proposed Millennium Pipeline Project
The proposed Millennium Pipeline Project (Millennium 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 approximately 700,000 Dth per day to eastern markets.
There are currently eight shippers who have signed agreements for a significant
portion, in aggregate, of the available capacity. Based on delays attributed to
the regulatory approval process at the FERC, the Millennium Project sponsors
have advised the FERC of a revised in-service date of November 1, 2002.

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

Volunteer Pipeline
On April 14, 1999, Columbia Gulf, MCN Energy Group, Inc. and AGL Resources, Inc.
announced the start of an open season on the proposed Volunteer Pipeline
(Volunteer). They were offering approximately 250,000 Dth per day of capacity in
a natural gas pipeline extending approximately 160 miles from an interconnection
near Portland, Tennessee to an interconnection near Chattanooga, Tennessee.
Subsequent to the open season, AGL Resources, Inc. withdrew its participation in
the project. Volunteer anticipates additional interconnections with several
pipeline companies including Columbia Gulf who will also serve as operator of
the new pipeline facilities.

At the end of the open season in May 1999, nearly a dozen companies requested
more than 440,000 Dth per day of capacity on Volunteer. Volunteer expects to
provide firm natural gas transportation from the mid-continent into the Atlanta,
Georgia, and other southeastern markets. Volunteer is currently in the process
of negotiating with potential shippers, and the timing of a FERC construction
application is contingent upon a final determination of market demand based upon
these negotiations. Volunteer is exploring several construction options and
timelines that would have the pipeline in place to meet market demand as it
evolves.

Competition and the Effect of LDC Unbundling Services
Columbia's transmission and storage subsidiaries compete with other interstate
pipelines for the transportation and storage of natural gas. Since the issuance
of FERC Order No. 636, various states throughout Columbia Transmission's service
area have initiated proceedings dealing with open access and unbundling of LDC
services. Among other things, unbundling involves providing all LDCs with the
choice of what entity will serve as transporter as well as merchant supplier.
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 that 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 that 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 contracts.
However, in view of the changing market and regulatory environment, Columbia's
transmission companies have commenced the process of discussing long-term
transportation and storage service needs with their firm customers. Those
discussions could result in the restructuring of some of these contracts on
mutually agreeable terms prior to 2004.

Regulatory Matters
                                  Mainline `99
Columbia Gulf filed an application with the FERC in June 1998 for authority to
increase the maximum certificated capacity of its mainline facilities. Columbia
Gulf's largest expansion of its mainline facilities, referred to as


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


Mainline `99, was authorized by the FERC in February 1999. The Mainline `99
project has increased Columbia Gulf's certificated capacity to nearly 2.2
Bcf/day by replacing certain compressor units and increasing the horsepower
capacity of other compressor stations. On December 1, 1999, approximately
270,000 Dth/day of additional capacity was made available on Columbia Gulf's
mainline and approximately 45,000 Dth/day of additional capacity was made
available on the mainline on November 1, 2000, following the construction of all
of the facilities authorized by the FERC as part of the Mainline `99 project.
Appeals challenging the FERC's authorization of the Mainline `99 facilities have
been filed and are pending before the United States Court of Appeals for the
District of Columbia.

                              Discussions with FERC
The transmission and storage subsidiaries were in confidential discussions with
the staff of the FERC to resolve a previously disclosed regulatory issue. In
late October 2000, the FERC issued an order approving a settlement between the
FERC staff and the transmission subsidiaries resolving all regulatory issues.
The financial impact of this settlement was recorded in the third quarter of
2000 and was not material to consolidated results.

                   Columbia Gulf Mainline Capacity Proceeding
In 1993, the FERC directed Columbia Gulf to show cause as to why it had not
sought FERC abandonment authorization to reduce capacity on its mainline
facility. In an August 8, 1997 order, the FERC approved a settlement between
Columbia Gulf and FERC's enforcement staff requiring 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. In orders issued in December 1998 and 1999,
the FERC has rejected challenges to the settlement and denied rehearing. In its
order issued December 22, 1999, the FERC affirmed the validity of the 1997 open
season but indicated that an additional open season in compliance with the
settlement will be necessary. In early February 2000, several appeals of the
FERC's orders in this proceeding were filed with the federal circuit court of
appeals and are still pending.

Columbia Gulf Voluntary Severance Plan
Columbia Gulf announced a voluntary severance plan (VSP) on September 19, 2000,
for its workforce to assist in the elimination of approximately 70 positions.
The positions were eliminated by December 31, 2000. The cost of the VSP was
approximately $6.6 million and was recognized in the fourth quarter of 2000.

Storage Base Gas Sales
Columbia Transmission has agreements to sell 5.2 Bcf of base gas volumes in the
first quarter of 2001. In addition, Columbia also sold 4.8 Bcf of base gas
volumes in the first quarter of 2000 and 7 Bcf in the first quarter of 1999
resulting in a pre-tax gain of $10.9 and $14.4 million, respectively. Base gas
represents storage volumes that are maintained to ensure that adequate pressure
exists to deliver current inventory. However, as a result of ongoing
improvements made in Columbia Transmission's storage operations, there are
instances when these storage volumes are determined to be unnecessary to
maintain deliverability of current inventory. As a result of first quarter 2000
base gas sales, Columbia Transmission reached the cumulative $60 million pre-tax
gain level above which it must share any future gains equally with its customers
pursuant to the terms of a prior rate settlement.

Capital Expenditure Program
The transmission and storage segment's net capital expenditure program was
$128.9 million in 2000 and is projected to be approximately $132 million in
2001. New business initiatives totaled approximately $24 million in 2000 and are
expected to be $49.2 million in 2001. The remaining expenditures are for
modernizing and upgrading facilities.

Environmental Matters
Columbia Transmission continues to conduct assessment, characterization and
remediation activities at specific sites under a 1995 Environmental Protection
Agency (EPA) Administrative Order by Consent (AOC). The program pursuant to the
AOC covers approximately 240 facilities, approximately 13,000 liquid removal
points, approximately 2,200 mercury measurement stations and about 3,700 storage
well locations. As of December 31, 2000, field characterization has been
performed at almost all of these sites, with the exception of the storage well
locations. Site characterization reports and remediation plans, which must be
submitted to the EPA for approval, are in various stages of development and
completion. Characterization of the storage well locations were initiated in the
fall of 2000 and are yet to be completed. Significant remediation has taken
place at mercury measurement stations, liquid removal point sites, and at a
limited number of the 240 facilities.


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


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). As costs become probable and reasonably estimable,
the associated reserves will be adjusted as appropriate. Columbia Transmission
is unable, at this time, to accurately estimate the time frame and potential
costs of the entire program. Management expects that as characterization is
completed and approved by the EPA, additional remediation work is performed and
more facts become available, Columbia Transmission will be able to develop a
probable and reasonable estimate for the entire program or a major portion
thereof consistent with 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.

At the end of 2000, the remaining environmental liability recorded on the
balance sheet for the gas transmission and storage operations was $104.5
million. Columbia Transmission's environmental cash expenditures are expected to
be approximately $16 million in 2001 and to remain at this level in the
foreseeable future. These expenditures will be charged against the previously
recorded liability. A regulatory asset has been recorded to the extent
environmental expenditures are expected to be recovered through rates.
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, existing laws, regulations, its cost
recovery settlement with customers and the long time 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. Columbia Transmission is as yet unable to determine if it will become
liable for any characterization or remediation costs at such sites.

Throughput
Columbia Transmission's throughput consists of transportation and storage
services for LDCs and other customers within its market area. Throughput for
Columbia Gulf reflects mainline transportation services from Rayne, Louisiana to
Leach, Kentucky and short-haul transportation services from the Gulf of Mexico
to Rayne, Louisiana.

In 2000, throughput for the transmission and storage segment of 1,267.3 Bcf
increased 16.5 Bcf over 1999, due to colder weather, increased mainline
requirements, and increased transportation services from Columbia Transmission's
market expansion project. Market area transportation by Columbia Transmission of
1,043 Bcf increased by 37.3 Bcf. Mainline transportation for Columbia Gulf
increased 23.2 Bcf in 2000, reflecting the impact of colder weather in Columbia
Transmission's operating territory and the sale of all of the remaining Mainline
`99 capacity. Short-haul transportation of 194.7 Bcf in 2000 was down 25.5 Bcf
from 1999, due to a reduced need for transportation services and reduced
throughput from off system supply sources.

Throughput for 1999 of 1,250.8 Bcf increased 53.3 Bcf when compared to the year
earlier primarily due to colder weather in 1999 and increased transportation
services from Columbia Transmission's market expansion project. Market area
transportation of 1,005.7 Bcf by Columbia Transmission increased 57.9 Bcf in
1999. Mainline transportation for Columbia Gulf increased 30.9 Bcf in 1999 over
1998, reflecting the impact of colder weather in Columbia Transmission's
operating territory. Short-haul transportation of 220.2 Bcf in 1999 was down 11
Bcf from 1998, due to a decline in market demand in the area south of Rayne,
Louisiana.

Operating Revenues
Operating revenues of $855.8 million in 2000 were up $19.4 million over 1999.
After adjusting for revenue items that are offset in operating expenses,
operating revenues increased by $14.5 million, due to increased transportation
services and higher revenues related to Columbia Transmission's market expansion
projects.

Operating revenues in 1999 of $836.4 million were essentially unchanged from
1998. After adjusting for revenue items that are offset in operating expenses,
operating revenues in 1999 increased by $6.1 million primarily due to an
increase in Columbia Transmission's market expansion contracts.

Operating Income
In 2000, operating income for the transmission and storage segment of $264.9
million decreased $85.2 million from 1999. This decrease primarily reflected the
impact of merger-related expenditures and the favorable impact of a 1999
producer settlement. The 2000 results benefited from increased transportation
services and higher revenues related to Columbia Transmission's market expansion
project in addition to the positive impact of lower operating costs as a result
of the VIRP.


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


Operating income of $350.1 million for 1999 increased $24 million over 1998.
This increase primarily reflected the pre-tax benefit of a producer settlement
and higher revenues primarily resulting from Columbia Transmission's market
expansion project.

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


<TABLE>
<CAPTION>
Year Ended December 31, (in millions)       2000          1999          1998
-----------------------------------------------------------------------------
OPERATING REVENUES
<S>                                     <C>           <C>           <C>
   Transportation revenues               $ 649.3       $ 615.0       $ 620.4
   Storage revenues                        177.8         182.4         186.0
   Other revenues                           28.7          39.0          32.3
-----------------------------------------------------------------------------
Total Operating Revenues                   855.8         836.4         838.7
-----------------------------------------------------------------------------
OPERATING EXPENSES
   Operation and maintenance               427.9         358.9         358.9
   Settlement of gas supply charges            -         (31.7)            -
   Depreciation                            109.3         106.2         101.8
   Other taxes                              53.7          52.9          51.9
-----------------------------------------------------------------------------
Total Operating Expenses                   590.9         486.3         512.6
-----------------------------------------------------------------------------
OPERATING INCOME                         $ 264.9       $ 350.1       $ 326.1
-----------------------------------------------------------------------------
</TABLE>


                  TRANSMISSION AND STORAGE OPERATING HIGHLIGHTS


<TABLE>
<CAPTION>
                                           2000       1999      1998      1997       1996
------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions)      128.9      183.4     210.0     251.4      142.7
------------------------------------------------------------------------------------------
THROUGHPUT (Bcf)
<S>                                    <C>        <C>       <C>       <C>        <C>
Transportation
   Columbia Transmission
      Market area                       1,043.0    1,005.7     947.8   1,032.6    1,102.4
   Columbia Gulf
      Mainline                            617.4      594.2     563.3     607.5      633.7
      Short-haul                          194.7      220.2     231.2     252.4      266.5
      Intrasegment eliminations          (587.8)    (569.3)   (544.8)   (591.0)    (624.5)
------------------------------------------------------------------------------------------
TOTAL THROUGHPUT                        1,267.3    1,250.8   1,197.5   1,301.5    1,378.1
------------------------------------------------------------------------------------------
</TABLE>


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


                             DISTRIBUTION OPERATIONS

Columbia's five distribution subsidiaries (Distribution) provide natural gas
service to nearly 2.1 million residential, commercial and industrial customers
in Ohio, Pennsylvania, Virginia, Kentucky and Maryland.

Market Conditions
Weather in Distribution's market area during 2000 was 9% colder than 1999. As a
result, Distribution's weather-sensitive deliveries were up 43 Bcf from 1999.

Competition
Distribution competes with investor-owned, municipal, and cooperative electric
utilities throughout its five-state service area, and to a lesser extent with
propane and fuel oil suppliers. Electric competition is generally strongest in
the residential and commercial markets of Kentucky, southern Ohio, southwestern
Pennsylvania and western Virginia where rates are primarily driven by low-cost
coal-fired generation. The northern Ohio and Pittsburgh areas have less
competitive electric rates due to the use of higher-cost nuclear-generated
power. It is too soon to determine what impact, if any, deregulation of the
electric industry will have on the competitive situation. Distribution continues
to be a strong competitor in the energy market for new homes as a result of
strong customer preference for natural gas.

Approximately 35% of Distribution's industrial and commercial throughput, or 122
Bcf, is susceptible to bypass because these customers are located close to
multiple natural gas pipelines and local gas distribution companies. As a result
of Distribution's competitive strategies, substantial inroads by other natural
gas competitors have been avoided to date.

Regulatory Matters
In December 1999, the Public Utilities Commission of Ohio (PUCO) approved a
request from Columbia of Ohio that extends Columbia of Ohio's Customer
CHOICE(SM) program through October 31, 2004, freezes base rates through October
31, 2004, and resolves the issue of transition capacity costs. Under the
agreement, Columbia of Ohio would assume total financial risk for mitigation of
transition capacity costs at no additional cost its to customers. Among other
items, Columbia of Ohio has the opportunity to utilize non-traditional revenue
sources as a means of offsetting the costs. Columbia of Ohio extended its
Customer CHOICE(SM) program to all of its nearly 1.3 million customers in
mid-1998 and there are over 470,850 customers participating, including
approximately 429,000 residential customers.

In April 1999, Columbia Gas of Kentucky, Inc. (Columbia of Kentucky) filed an
application with the Kentucky Public Service Commission (KPSC), seeking approval
to initiate a residential and small commercial transportation program. In
January 2000, the KPSC approved Columbia of Kentucky's application, but did not
renew Columbia of Kentucky's gas cost incentive program originally approved in
1996. As an alternative, an incentive sharing mechanism was approved that allows
Columbia of Kentucky to retain 25% of annual off-system sales over the term of
the pilot program. Additionally, Columbia of Kentucky will remain responsible
for mitigating transition capacity costs through the utilization of
non-traditional revenues. Columbia of Kentucky began customer enrollment in the
pilot program in September 2000, for gas deliveries beginning November 1, 2000.
The program is scheduled to run through 2004. Currently, Columbia of Kentucky
has approximately 14,000 customers enrolled and participating in its CHOICE(SM)
program.

The tightening of supply in the natural gas market over the last half of 2000,
along with the resultant increase in price of natural gas, has caused several
marketers to default on their obligation to deliver gas to Columbia of Ohio and
Columbia of Kentucky under both the traditional and CHOICE(SM) transportation
programs. Columbia of Ohio and Columbia of Kentucky have terminated marketers
with 19,500 customers in traditional and CHOICE(SM) transportation programs.

Columbia of Ohio is also a party to two lawsuits involving Energy Max, one of
the terminated marketers. A customer in Toledo, Ohio filed the first suit on
October 18, 2000 against both Energy Max and Columbia of Ohio, asking that the
complaint be certified as a class action (Hull v. Columbia Gas of Ohio and
Energy Max). The plaintiff is seeking to recover the difference between what he
would have paid for gas under his Energy Max contract, and what he is paying
under Columbia of Ohio's gas costs recovery rate. On January 26, 2001, Columbia
of Ohio filed its Answer and a Motion to Dismiss. Energy Max has not filed an
answer and is subject to a motion for default judgement. The second suit was
filed by Columbia of Ohio against Energy Max on January 2, 2001 in


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


Youngstown, Ohio (Columbia Gas of Ohio v. Energy Max). In this case, Columbia of
Ohio is seeking to recover in excess of $340,000 from Energy Max due to its
non-delivery of gas in Columbia of Ohio's traditional transportation program.
Columbia of Ohio has been given the right to bill the end users for their gas
consumption during the months of November and December 2000. The Ohio Office of
Consumers' Counsel has also filed a complaint at the PUCO against certain
marketers, but Columbia of Ohio is not a party to that complaint at this time.

FERC Order No. 637
The FERC issued Order No. 637 on February 9, 2000. The order sets forth
revisions to FERC regulations governing short-term natural gas transportation
services and policies governing the regulation of interstate natural gas
pipelines. Among other things, the order lifts the price cap for short-term
capacity release by pipeline customers for an experimental period ending
September 1, 2002.

Distribution is currently in the process of evaluating the potential changes and
impact Order 637 may have on operations; however, it is not anticipated that the
implementation of Order 637 will have a material impact on Columbia's
consolidated results.

Capital Expenditure Program
Distribution's 2000 capital expenditures were $139.6 million, a decrease of $5.9
million from 1999. In addition to maintaining and upgrading facilities to assure
safe, reliable and efficient operation, 2000 expenditures included $56.4 million
for extending service to new areas and $60.4 million for replacement and
betterment projects. The estimated 2001 capital expenditure program amounts to
approximately $113 million, including $51 million for new business and
development, with the remainder primarily for support services and replacement
and betterment projects.

Environmental Matters
Distribution's primary environmental issues relate to 18 former manufactured gas
plant sites. Investigations or remedial activities are currently underway at six
sites and remedial construction has been completed at two sites. Additional site
investigations may be required at some of the remaining sites. To the extent
Distribution's site investigations have been conducted, remediation plans
developed and the responsibility for remediation established, the appropriate
estimated liabilities have been recorded. Regulatory assets have also been
recorded for a majority of these costs as rate recovery has been authorized or
is probable.

In June 1999, Columbia Gas of Pennsylvania (Columbia of Pennsylvania), was
notified by the United States Environmental Protection Agency (USEPA) Region 5,
that it was the potential responsible party (PRP) under the Comprehensive
Environmental Response Compensation and Liability Act (CERCLA) concerning a site
in Wooster, Ohio, known as 7-7 Merger, Inc. Columbia of Pennsylvania, along with
23 other parties, entered into an Administrative Consent order with USEPA Region
5 and the work was nearly completed during the year 2000.

The PRP group working with Region 5 shared costs on this project. Columbia of
Pennsylvania's share of the cost is $20,000. With additional miscellaneous
costs, it is not anticipated that Columbia of Pennsylvania's liability will
exceed $25,000 for this project. Only a minor amount of disposal remains to be
accomplished during 2001 and there is sufficient funding in the PRP to fund the
balance of this work.

Throughput
In 2000, total volumes sold and transported of 551.5 Bcf decreased 145.3 Bcf
from 1999. The decreased throughput primarily reflects a 159.8 Bcf decrease in
off-system sales partially offset by increased transportation services.

Distribution's 1999 total volumes sold and transported of 696.8 Bcf increased
138.6 Bcf from 1998 primarily due to an increase in off-system sales as
Distribution took advantage of higher spot prices in March 1999.

Net Revenues
Net revenues for 2000 of $886.7 million were up $34.1 million over 1999
primarily due to increased transportation services.

In 1999, net revenues of $852.6 million were up $5.6 million over 1998
reflecting the positive impact of Columbia of Virginia's regulatory settlement
and increased customer usage as a result of colder weather, partially offset by
the impact of lower sales due to the switch to CHOICE(SM) transportation
services.


                                       21

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

Operating Income

Operating income for 2000 of $176 million decreased $78.6 million from 1999,
primarily due to $100.9 million in costs related to merger-related and
restructuring activities. Partially offsetting these decreases was the favorable
impact of the 1997 Columbia of Ohio regulatory settlement and reduced employee
related costs as a result of the VIRP.

Operating income in 1999 of $254.6 million increased by $28.8 million over 1998,
primarily due to the increase in net revenues, reduced operating expenses
attributable to lower gross receipts and property taxes, as noted above.
However, the favorable effect of lower depreciation expense attributable to the
1999 Columbia of Ohio regulatory settlement is offset by charges to revenues for
reserves established for recovery of future stranded costs as provided for under
this settlement and therefore has no effect on operating income.



     STATEMENTS OF OPERATING INCOME FROM DISTRIBUTION OPERATIONS (UNAUDITED)


<TABLE>
<CAPTION>
Year Ended December 31, (in millions)                                                     2000             1999              1998

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

<S>                                                                                  <C>              <C>               <C>
NET REVENUES
   Sales revenues                                                                    $ 1,684.5        $ 1,705.5         $ 1,686.3
   Less: Cost of gas sold                                                              1,124.9          1,137.6           1,005.4

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

   Net Sales Revenues                                                                    559.6            567.9             680.9

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

   Transportation revenues                                                               351.4            317.3             183.2
   Less: Associated gas costs                                                             24.3             32.6              17.1

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

   Net Transportation Revenues                                                           327.1            284.7             166.1

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

Net Revenues                                                                             886.7            852.6             847.0

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

OPERATING EXPENSES
   Operation and maintenance                                                             523.4            406.9             386.7
   Depreciation                                                                           57.4             54.5              82.2
   Other taxes                                                                           129.9            136.6             152.3

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

Total Operating Expenses                                                                 710.7            598.0             621.2

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

OPERATING INCOME                                                                       $ 176.0          $ 254.6           $ 225.8

----------------------------------------------------------------------------------------------------------------------------------
</TABLE>



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

                        DISTRIBUTION OPERATING HIGHLIGHTS


<TABLE>
<CAPTION>
                                                 2000            1999           1998           1997            1996

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

<S>                                          <C>              <C>            <C>            <C>             <C>
CAPITAL EXPENDITURES ($ in millions)              139.6           145.5          151.9          159.5           148.4
------------------------------------------------------------------------------------------------------------------------

THROUGHPUT (Bcf)
Sales
   Residential                                    130.6           132.5          149.1          190.9           209.4
   Commercial                                      45.0            43.7           54.1           72.7            85.7
   Industrial and Other                             4.2             3.5            4.4            4.2            10.3
------------------------------------------------------------------------------------------------------------------------

Total Sales                                       179.8           179.7          207.6          267.8           305.4
Transportation                                    360.6           346.2          287.7          258.9           248.8

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

Total Throughput                                  540.4           525.9          495.3          526.7           554.2
Off-System Sales                                   11.1           170.9           62.9           45.4            10.8
------------------------------------------------------------------------------------------------------------------------

Total Sold and Transported                        551.5           696.8          558.2          572.1           565.0

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

SOURCES OF GAS FOR THROUGHPUT  (Bcf)
Sources of Gas Sold
   Spot market*                                   284.8           302.2          229.8          314.0           323.2
   Producers                                       10.6            12.6           20.8           38.9            50.2
   Storage withdrawals (injections)                (0.4)           15.5           12.4            4.0           (20.8)
   Company use, exchange and other               (104.1)           20.3            7.5          (43.7)          (36.4)
------------------------------------------------------------------------------------------------------------------------

Total Sources of Gas Sold                         190.9           350.6          270.5          313.2           316.2
Gas received for delivery to customers            360.6           346.2          287.7          258.9           248.8
------------------------------------------------------------------------------------------------------------------------

Total Sources                                     551.5           696.8          558.2          572.1           565.0
------------------------------------------------------------------------------------------------------------------------

CUSTOMERS
Sales
   Residential                                1,387,801       1,366,869      1,612,124      1,769,647       1,815,269
   Commercial                                   127,504         123,673        148,529        168,413         173,689
   Industrial and Other                           2,205          2,264           2,295          2,340           2,285

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

Total Sales Customers                         1,517,510       1,492,806      1,762,948      1,940,400       1,991,243
Transportation                                  534,854         603,901        298,107         93,923          12,804
------------------------------------------------------------------------------------------------------------------------

Total Customers                               2,052,364       2,096,707      2,061,055      2,034,323       2,004,047
------------------------------------------------------------------------------------------------------------------------

DEGREE DAYS                                       5,610           5,171          4,635          5,736           5,975

------------------------------------------------------------------------------------------------------------------------
</TABLE>

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



                      EXPLORATION AND PRODUCTION OPERATIONS

Columbia's exploration and production subsidiary, Columbia Resources, is one of
the largest independent natural gas and oil producers in the Appalachian Basin
and also has production operations in Ontario, Canada and the Canadian
Maritimes. Columbia Resources produced 53.7 Bcf equivalents (Bcfe) of natural
gas and oil in 2000 and has financial interests in approximately 8,000 wells,
and has net proven gas and oil reserve holdings of 1.1 trillion cubic feet
equivalent at December 31, 2000. Columbia Resources also owns and operates
approximately 6,200 miles of gathering pipelines.

Columbia Resources seeks to achieve asset and profit growth primarily through
expanded drilling activities. During 2000, Columbia Resources' drilling activity
resulted in the discovery of 78.6 net Bcfe of gas and oil reserves. For 1999,
reserves of 69.5 Bcfe were developed. Through December 2000, Columbia Resources
has participated in 259 gross (239 net) wells with a success rate of 85 percent
compared to 263 gross (240 net) wells with a success rate of 82 percent in 1999.

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

Capital Expenditure Program

Columbia Resources' 2000 capital expenditures of $128.9 million primarily
reflect investments in drilling and production activities. The 2001 capital
expenditure program is estimated at $132 million and provides for the drilling
of 223 new wells in the Appalachian Basin and Canada. This investment will
include the expansion of Columbia Resources' gathering facilities in the
Appalachian Basin and the continued expansion of its acreage position.

Forward Sale of Natural Gas

On August 24, 2000, Columbia Resources entered into an agreement with Mahonia II
Limited, whereby Columbia Resources agreed to sell 111.7 Bcf of natural gas to
Mahonia for the period August 2000, through July 2005. This forward sale
provided $246.4 million in cash proceeds, net of expenses.

Production

Gas production of 52.4 Bcf in 2000 increased 6.6 Bcf over 1999, primarily due to
new well completions coming on-line.

In 1999, gas production of 45.8 Bcf increased 6.7 Bcf over 1998, primarily due
to the acquisition of Wiser Oil and Meridian Exploration. Oil and liquids
production in 1999 decreased 14% from 1998 to 185,207 barrels primarily
reflecting normal production declines in Ohio wells.

Operating Revenues

Operating revenues for 2000 of $178.5 million increased $33.7 million over 1999.
The increase reflects higher average natural gas prices that were $2.99 per Mcf
in 2000 compared to $2.66 per Mcf in 1999. Approximately 63% of Columbia
Resources' natural gas production for 2000 was hedged or committed through fixed
price contracts at an average price of $3.51 per Mcf.

Operating revenues for 1999 of $144.8 million increased $17.3 million over 1998
reflecting increased gas production that was partially offset by lower average
1999 gas prices. Also contributing to the increase in operating revenues in 1999
was $6 million of revenues received from the termination of long-term sales
contracts with two co-generation facilities.

Operating Income

Operating income of $49.3 million for 2000 increased $5.1 million over 1999
reflecting the impact of higher natural gas production and a lower depletion
rate in effect due to higher commodity prices. Tempering this increase were
merger-related expenditures of $17.6 million and expenses related to the
implementation of the VIRP.

In 1999, operating income of $44.2 million improved $7 million over 1998
reflecting higher operating revenues, partially offset by higher operating
expense due largely to costs related to acquisitions and increased drilling
activity.




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


<TABLE>
<CAPTION>
Year Ended December 31, (in millions)        2000              1999          1998
---------------------------------------------------------------------------------------

<S>                                         <C>            <C>            <C>
OPERATING REVENUES
   Gas revenues                             $  159.5       $  123.1       $  113.9
   Other revenues                               19.0           21.7           13.6
---------------------------------------------------------------------------------------

Total Operating Revenues                       178.5          144.8          127.5
---------------------------------------------------------------------------------------

OPERATING EXPENSES
   Operation and maintenance                    82.3           53.9           44.6
   Depreciation and depletion                   33.0           36.9           36.5
   Other taxes                                  13.9            9.8            9.2
---------------------------------------------------------------------------------------

Total Operating Expenses                       129.2          100.6           90.3
---------------------------------------------------------------------------------------

OPERATING INCOME                            $   49.3       $   44.2       $   37.2
---------------------------------------------------------------------------------------
</TABLE>

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


                EXPLORATION AND PRODUCTION OPERATING HIGHLIGHTS


<TABLE>
<CAPTION>
                                                  2000          1999            1998            1997            1996

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

<S>                                            <C>              <C>             <C>              <C>            <C>
CAPITAL EXPENDITURES ($ in millions)             128.9           166.5            75.7           135.6            12.1

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

PROVED RESERVES
Gas (Bcf)                                      1,099.6           951.6           790.5           800.5           644.5
Oil and Liquids (000 Bbls)                       1,399           2,375           1,835           1,700             774

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

PRODUCTION
Gas (Bcf)                                         52.4            45.8            39.1            34.7            33.6
Oil and Liquids (000 Bbls)                         215             185             214             210             281

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

AVERAGE PRICES
Gas ($ per Mcf)*                                  2.99            2.66            2.91            2.63            2.84
Oil and Liquids ($ per barrel)                   25.29           14.96           12.76           17.99           19.07

-----------------------------------------------------------------------------------------------------------------------
</TABLE>

* Includes the effect of hedging activities as discussed in Note 7 of Notes to
Consolidated Financial Statements.


                           OTHER PRODUCTS AND SERVICES

Telecommunications Network

In 1999, Transcom, a wholly-owned subsidiary of Columbia, began the construction
of its telecommunications network between New York and Washington, D.C. Transcom
is building its fiber optics network primarily on rights-of-way of Columbia's
pipeline companies. The route covers 260 miles and provides access to 16 million
people in the busiest telecommunications corridor in the United States. Transcom
expects to complete the D.C. to New York fiber optics link in the first half of
2001. Columbia is currently pursuing strategic alternatives for its
telecommunications network.

Sale of Columbia Electric

In December, Columbia Electric sold its interests in four power generation
plants to a partnership between Delta Power Company and John Hancock Life
Insurance Company. These facilities include the Gregory Power Project in Corpus
Christi, Texas; a co-generation facility in Rumford, Maine; and two
combined-cycle facilities, one located near Pedericktown, New Jersey and the
other near Vineland, New Jersey. These projects are qualifying facilities under
the Public Utility Regulatory Policies Act (PURPA). Also in December, Columbia
sold the remainder of Columbia Electric to Orion Power Holdings, Inc.

In aggregate, the sale of Columbia Electric and its operations resulted in a
gain that improved Columbia's consolidated results by approximately $86 million
after-tax.

Capital Expenditures

The capital expenditure program for 2000 was $96 million and included amounts
for the development of Transcom's fiber optics network. The 2001 program is
projected to be $2 million for miscellaneous activities.

Environmental Matters

In spring 2000, Transcom received directives from The Philadelphia District of
the U.S. Army Corps of Engineers (Philadelphia District) and an administrative
order from the PA DEP addressing alleged violations of federal and state laws
resulting from construction activities associated with the corporation's laying
of fiber optic cable along portions of a route between Washington, D.C. and New
York City. The order and directives required Transcom to largely cease
construction activities. On September 18, 2000, Transcom entered into a
voluntary settlement agreement with the Philadelphia District under which
Transcom contributed $1.2 million to the Pennsylvania chapter of the Nature
Conservancy and the Philadelphia District lifted its directives. As a result of
the voluntary agreement with the Philadelphia District and communications with
the PA DEP, the Maryland Department of Environment and the Baltimore District of
the U.S. Army Corps of Engineers, work in Pennsylvania and Maryland is now
ongoing. Transcom cannot predict the effect of the ongoing discussions on the
completion schedule for the

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


project, nor the nature or amount of total remedies that may be sought in
connection with the foregoing construction activities.

Operating Revenues
In 2000, operating revenues of $50.1 million decreased $46.2 million from 1999
million largely due to a gain in 1999 resulting from the termination of a
long-term power purchase contract between Columbia Electric and Atlantic
Generation, Inc.

In 1999, operating revenues of $96.3 million increased $73.1 million over 1998.
The increase largely reflected the gain from the termination of the power
purchase contract previously mentioned.

Operating Income (Loss)
In 2000, the other products and services segment reported an operating loss of
$32.3 million compared to operating income of $63.8 million in 1999. The 1999
results included a gain from the termination of the power purchase contract,
mentioned above. The higher operating expenses in 2000 included $10.8 million of
merger-related expenditures and employee-related payments resulting from the
achievement of specific objectives in the development of co-generation projects
by Columbia Electric.

In 1999, operating income of $63.8 million increased $61.5 million from 1998 as
the increase in operating revenues was only partially offset by a $11.6 increase
in operating expenses.


              STATEMENTS OF OTHER PRODUCTS AND SERVICES (UNAUDITED)


<TABLE>
<CAPTION>
Year Ended December 31, (in millions)          2000            1999           1998
------------------------------------------------------------------------------------

<S>                                         <C>             <C>            <C>
OPERATING REVENUES
   Gas revenues                             $  35.0         $   7.7        $   4.0
   Power generation revenues                    8.8            78.5            8.3
   LNG revenues                                 3.8             9.3           10.4
   Other revenues                               2.5             0.8            0.5
-------------------------------------------------------------------------------------

Total Operating Revenues                       50.1            96.3           23.2
------------------------------------------------------------------------------------

OPERATING EXPENSES
   Products purchased                          26.6             4.9            0.5
   Operation and maintenance                   55.0            26.8           19.9
   Depreciation                                 0.2             0.4            0.3
   Other taxes                                  0.6             0.4            0.2
------------------------------------------------------------------------------------

Total Operating Expenses                       82.4            32.5           20.9
------------------------------------------------------------------------------------


OPERATING INCOME (LOSS)                     $ (32.3)        $  63.8        $   2.3
------------------------------------------------------------------------------------
</TABLE>



   OTHER PRODUCTS AND SERVICES OPERATING HIGHLIGHTS


<TABLE>
<CAPTION>
                                                2000          1999         1998          1997          1996
-------------------------------------------------------------------------------------------------------------
<S>                                             <C>           <C>          <C>           <C>           <C>
CAPITAL EXPENDITURES ($ in millions)            96.0          57.3          12.1          1.5          0.2
-------------------------------------------------------------------------------------------------------------
</TABLE>


                                       26
<PAGE>   27
ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


Information required by this item is in Item 7 beginning on page 14.


                                       27
<PAGE>   28
ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

<TABLE>
<CAPTION>
Index                                                                                                                    Page
<S>                                                                                                                      <C>
Report of Independent Public Accountants. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     29
Statements of Consolidated Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     30
Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     31
Statements of Consolidated Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     33
Statements of Consolidated Common Stock Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    34
Notes of Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    35
Schedule II - Valuation and Qualifying Accounts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    57
</TABLE>

                                       28
<PAGE>   29
ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA  (continued)



                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS


To the Shareholder of Columbia Energy Group:


We have audited the accompanying consolidated balance sheets of Columbia Energy
Group (a Delaware corporation, the "Corporation" and a wholly-owned subsidiary
of NiSource Inc.) and subsidiaries as of December 31, 2000, and 1999, 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, 2000. 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 auditing standards generally accepted
in the United States. 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, 2000, and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.

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 30, 2001

                                       29
<PAGE>   30
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)                           2000                1999                1998
-------------------------------------------------------------------------------------------------------------
<S>                                                         <C>                <C>                <C>
NET REVENUES
   Energy sales                                             $  1,723.1         $  1,717.8         $  1,651.1
   Less:  Products purchased                                     922.5              892.9              722.2
-------------------------------------------------------------------------------------------------------------

   Gross Margin                                                  800.6              824.9              928.9
   Transportation                                                801.2              706.5              577.2
   Production gas sales                                          154.9              120.2              111.8
   Other                                                         179.8              256.4              206.0
-------------------------------------------------------------------------------------------------------------

Total Net Revenues                                             1,936.5            1,908.0            1,823.9
-------------------------------------------------------------------------------------------------------------

OPERATING EXPENSES
   Operation and maintenance (Note 4)                          1,110.5              838.6              790.5
   Settlement of gas supply charges                             --                  (31.7)            --
   Depreciation and depletion                                    205.2              202.7              226.3
   Other taxes                                                   202.5              203.2              216.5

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

Total Operating Expenses                                       1,518.2            1,212.8            1,233.3
-------------------------------------------------------------------------------------------------------------

OPERATING INCOME                                                 418.3              695.2              590.6
-------------------------------------------------------------------------------------------------------------

OTHER INCOME (DEDUCTIONS)
   Interest income and other, net (Note 15)                      236.3               34.9               14.7
   Interest expense and related charges (Note 16)               (169.6)            (164.2)            (144.2)
-------------------------------------------------------------------------------------------------------------

Total Other Income (Deductions)                                   66.7             (129.3)            (129.5)
-------------------------------------------------------------------------------------------------------------

INCOME FROM CONTINUING OPERATIONS
   BEFORE INCOME TAXES                                           485.0              565.9              461.1
Income Taxes (Note 9)                                            190.4              178.1              152.2
-------------------------------------------------------------------------------------------------------------

INCOME FROM CONTINUING OPERATIONS                                294.6              387.8              308.9
-------------------------------------------------------------------------------------------------------------

DISCONTINUED OPERATIONS - NET OF TAXES
   (Loss) from operations                                         (1.5)            (112.8)             (39.7)
   Estimated (loss) on disposal                                 (159.4)             (25.8)            --
-------------------------------------------------------------------------------------------------------------

(Loss) from Discontinued Operations - net of taxes              (160.9)            (138.6)             (39.7)
-------------------------------------------------------------------------------------------------------------

NET INCOME                                                  $    133.7         $    249.2         $    269.2
-------------------------------------------------------------------------------------------------------------
</TABLE>

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

                                       30
<PAGE>   31
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)                           2000                1999
------------------------------------------------------------------------------------------------

<S>                                                            <C>                <C>
PROPERTY, PLANT AND EQUIPMENT
   Gas utility and other plant, at original cost               $  8,174.2         $  7,886.2
   Accumulated depreciation                                      (3,778.3)          (3,659.4)
------------------------------------------------------------------------------------------------


   Net Gas Utility and Other Plant                                4,395.9            4,226.8
------------------------------------------------------------------------------------------------

   Gas and oil producing properties, full cost method
      United States cost center                                     913.6              823.5
      Canadian cost center                                           20.2               12.6
   Accumulated depletion                                           (272.7)            (251.6)

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

   Net Gas and Oil Producing Properties                             661.1              584.5
------------------------------------------------------------------------------------------------

Net Property, Plant and Equipment                                 5,057.0            4,811.3
------------------------------------------------------------------------------------------------


INVESTMENTS AND OTHER ASSETS
   Unconsolidated affiliates                                         28.1               65.6
   Net assets of discontinued operations                            236.3              410.0
   Other                                                             27.4               61.4

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

Total Investments and Other Assets                                  291.8              537.0
------------------------------------------------------------------------------------------------


CURRENT ASSETS
   Cash and temporary cash investments                               73.5               58.1
   Accounts receivable
      Customer (less allowance for doubtful accounts
         of $15.8 and $11.3, respectively)                          569.8              401.7
      Affiliated                                                      2.7             --
      Other                                                         113.5               96.8
   Gas inventory                                                    147.4              144.9
   Other inventories - at average cost                               14.5               16.1
   Prepayments                                                       73.8               70.7
   Regulatory assets                                                 57.4               52.7
   Underrecovered gas costs                                         169.0               40.5
   Deferred property taxes                                           45.2               79.9
   Exchange gas receivable                                          615.9              275.4
   Other                                                             (2.3)              31.0

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

Total Current Assets                                              1,880.4            1,267.8

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

REGULATORY ASSETS                                                   351.8              358.1
DEFERRED CHARGES                                                     45.2               63.1
------------------------------------------------------------------------------------------------


TOTAL ASSETS                                                   $  7,626.2         $  7,037.3
------------------------------------------------------------------------------------------------
</TABLE>


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

                                       31
<PAGE>   32
ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA  (continued)


<TABLE>
<CAPTION>
CAPITALIZATION AND LIABILITIES as of December 31, (in millions)              2000               1999
-------------------------------------------------------------------------------------------------------

<S>                                                                      <C>                <C>
COMMON STOCK EQUITY
   Common stock, par value $.01 per share - issued
     79,539,295 and 83,786,942 shares, respectively                      $      0.8         $      0.8
   Additional paid in capital                                               1,369.0            1,611.6
   Retained earnings                                                          666.5              586.9
   Unearned employee compensation                                            --                   (0.6)
   Accumulated other comprehensive income:
     Foreign currency translation adjustment                                   (0.4)               0.3
   Treasury stock                                                            --                 (135.0)
-------------------------------------------------------------------------------------------------------

Total Common Stock Equity                                                   2,035.9            2,064.0
LONG-TERM DEBT (Note 11)                                                    1,639.1            1,639.3
-------------------------------------------------------------------------------------------------------

Total Capitalization                                                        3,675.0            3,703.3
-------------------------------------------------------------------------------------------------------

CURRENT LIABILITIES
   Short-term debt (Note 12)                                                  521.0              465.5
   Current maturities of long-term debt                                         0.2              311.1
   Accounts and drafts payable                                                398.0              240.8
   Affiliated payable                                                           7.2             --
   Accrued taxes                                                              177.1              216.1
   Accrued interest                                                            17.7               32.4
   Estimated rate refunds                                                       6.8               21.4
   Overrecovered gas costs                                                   --                   14.6
   Transportation and exchange gas payable                                    358.5              297.5
   Deferred revenue                                                           451.5               40.0
   Other                                                                      366.0              366.8
-------------------------------------------------------------------------------------------------------

Total Current Liabilities                                                   2,304.0            2,006.2
-------------------------------------------------------------------------------------------------------

OTHER LIABILITIES AND DEFERRED CREDITS
   Deferred income taxes - noncurrent                                         766.8              661.9
   Investment tax credits                                                      31.2               32.6
   Postretirement benefits other than pensions                                114.7               91.0
   Regulatory liabilities                                                      32.4               36.4
   Deferred revenue                                                           498.0              300.8
   Other                                                                      204.1              205.1
-------------------------------------------------------------------------------------------------------

Total Other Liabilities and Deferred Credits                                1,647.2            1,327.8
-------------------------------------------------------------------------------------------------------

COMMITMENTS AND CONTINGENCIES (Note 14)                                      --                 --
-------------------------------------------------------------------------------------------------------

TOTAL CAPITALIZATION AND LIABILITIES                                     $  7,626.2         $  7,037.3
-------------------------------------------------------------------------------------------------------
</TABLE>

                                       32
<PAGE>   33
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)                                   2000            1999            1998
---------------------------------------------------------------------------------------------------------------
<S>                                                                  <C>              <C>              <C>
OPERATING ACTIVITIES
   Net income                                                        $  133.7         $  249.2         $  269.2
   Adjustments to reconcile net income to net
         cash from continuing operations:
      Loss from discontinued operations                                   1.5            112.8             39.7
      Loss on disposal                                                  159.4             25.8           --
      Depreciation and depletion                                        205.2            202.7            226.3
      Deferred income taxes                                             119.5             47.6             35.7
      Gain on sale of investments                                      (221.0)          --               --
      Earnings from equity investment, net of distributions             (16.4)            23.3             (8.5)
      Deferred revenue                                                  197.2            109.4            124.4
      Other - net                                                        47.9            (59.0)             2.0
---------------------------------------------------------------------------------------------------------------
                                                                        627.0            711.8            688.8
   Changes in components of working capital:
      Accounts receivable, net of sale                                 (200.6)          (145.9)            66.8
      Sale of accounts receivable                                      --                 81.1           --
      Gas inventory                                                      (2.5)            41.1             40.8
      Prepayments                                                        (3.1)            (7.4)            (4.0)
      Accounts payable                                                  142.4             87.6              5.8
      Accrued taxes                                                     (58.1)            (2.5)            77.2
      Accrued interest                                                  (13.6)            15.1            (12.1)
      Estimated rate refunds                                            (14.6)           (37.8)            (9.2)
      Estimated supplier obligations                                   --                (40.6)            (1.5)
      Under/Overrecovered gas costs                                    (143.0)           (35.7)           (33.4)
      Exchange gas receivable/payable                                  (279.5)            78.4             62.1
      Deferred revenue                                                  411.5             27.9             12.1
      Other working capital                                              79.3              9.9            (14.0)
---------------------------------------------------------------------------------------------------------------
Net Cash From Continuing Operations                                     545.2            783.0            879.4
Net Cash From Discontinued Operations                                    12.8           (246.3)          (193.3)
---------------------------------------------------------------------------------------------------------------
Net Cash From Operating Activities                                      558.0            536.7            686.1
---------------------------------------------------------------------------------------------------------------
INVESTMENT ACTIVITIES
   Capital expenditures                                                (476.0)          (447.6)          (434.8)
   Purchases and sales of investments - net                             312.9            (62.1)            (8.7)
---------------------------------------------------------------------------------------------------------------
Net Investment Activities                                              (163.1)          (509.7)          (443.5)
---------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
   Retirement of long-term debt                                        (310.9)           (52.5)            (0.9)
   Dividends paid                                                       (54.1)           (71.8)           (63.9)
   Issuance of common stock                                               6.5             15.5             10.5
   Issuance (repayment) of short-term debt                               55.5            320.7           (182.4)
   Purchase of treasury stock                                          (114.1)          (135.0)          --
   Other financing activities                                            37.6            (66.6)           (11.6)
---------------------------------------------------------------------------------------------------------------
Net Financing Activities                                               (379.5)            10.3           (248.3)
---------------------------------------------------------------------------------------------------------------
Increase (decrease) in cash and temporary cash investments               15.4             37.3             (5.7)
Cash and temporary cash investments at beginning of year                 58.1             20.8             26.5
---------------------------------------------------------------------------------------------------------------
CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR                   $   73.5         $   58.1         $   20.8
---------------------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
   Cash paid for interest                                            $  162.7         $  148.6         $  147.0
   Cash paid for income taxes (net of refunds)                       $   69.2         $   61.6         $   38.2
---------------------------------------------------------------------------------------------------------------
</TABLE>

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


                                       33
<PAGE>   34
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
                                                        Outstanding **             Par                 Treasury            Paid In
(in millions, except for share amounts)                  (Thousands)              Value                 Stock              Capital
------------------------------------------------------------------------------------------------------------------------------------

<S>                                                     <C>                      <C>                   <C>                 <C>
Balance at December 31, 1997                                 55,496              $ 554.9                   $ -               $ 754.2
Comprehensive income:
   Net income
   Foreign currency translation adjustment


Comprehensive income

Cash dividends:
   Common stock
Common stock issued:
   Long-term incentive plan                                     231                  2.3                                         7.6
  Three-for-two stock split                                  27,785                277.9
------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998                                 83,512                835.1                     -                 761.8

Comprehensive income:
   Net income
   Foreign currency translation adjustment


Comprehensive income

Cash dividends:
   Common stock
Reduction in par from $10 to $.01 per share                                       (834.3)                                      834.3
Common stock issued:
   Long-term incentive plan                                     275                                                             15.5
Purchase of treasury stock                                   (2,479)                                    (135.0)
------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999                                 81,308                  0.8                (135.0)              1,611.6

Comprehensive income:
   Net income
   Foreign currency translation adjustment


Comprehensive income

Cash dividends:
   Common stock
Common stock issued:
   Long-term incentive plan                                     120                                                              6.5
Purchase of treasury stock                                   (1,889)                                    (114.1)
Retirement of treasury stock                                                                             249.1               (249.1)
------------------------------------------------------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 2000                                 79,539                $ 0.8                   $ -             $ 1,369.0
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>


<TABLE>
<CAPTION>
                                                                                                Accumulated
                                                                          Unearned                 Other
                                                     Retained             Employee              Comprehensive
(in millions, except for share amounts)              Earnings            Compensation            Income (Loss)         Total
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                  <C>                 <C>                    <C>                <C>
Balance at December 31, 1997                         $ 482.7                $ (1.1)                   $ -             $ 1,790.7
Comprehensive income:
   Net income                                          269.2                                                              269.2
   Foreign currency translation adjustment                                                           (0.2)                 (0.2)
                                                                                                                   -------------
Comprehensive income                                                                                                      269.0
                                                                                                                   -------------
Cash dividends:
   Common stock                                        (63.9)                                                             (63.9)
Common stock issued:
   Long-term incentive plan                                                    0.2                                         10.1
  Three-for-two stock split                           (278.5)                                                              (0.6)
------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998                           409.5                  (0.9)                  (0.2)              2,005.3

Comprehensive income:
   Net income                                          249.2                                                              249.2
   Foreign currency translation adjustment                                                            0.5                   0.5
                                                                                                                   -------------
Comprehensive income                                                                                                      249.7
                                                                                                                   -------------
Cash dividends:
   Common stock                                        (71.8)                                                             (71.8)
Reduction in par from $10 to $.01 per share                                                                                   -
Common stock issued:
   Long-term incentive plan                                                    0.3                                         15.8
Purchase of treasury stock                                                                                               (135.0)

------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999                           586.9                  (0.6)                   0.3               2,064.0

Comprehensive income:
   Net income                                          133.7                                                              133.7
   Foreign currency translation adjustment                                                           (0.7)                 (0.7)
                                                                                                                   -------------
Comprehensive income                                                                                                      133.0
                                                                                                                   -------------
Cash dividends:
   Common stock                                        (54.1)                                                             (54.1)
Common stock issued:
   Long-term incentive plan                                                    0.6                                          7.1
Purchase of treasury stock                                                                                               (114.1)
Retirement of treasury stock                                                                                                  -
------------------------------------------------------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 2000                         $ 666.5                   $ -                 $ (0.4)             $2,035.9
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>


The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
-------------
 *    Effective May 19, 1999, the authorized number of shares of common stock
      increased from 100 million to 200 million and the par value of common
      stock decreased from $10 to $.01 per share.
**    The common shares outstanding at December 31, 1997 do not reflect the
      three-for-two common stock split, in the form of a stock dividend,
      effective June 15, 1998.

                                       34
<PAGE>   35
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 1999 and
         1998 financial statements to conform to the 2000 presentation.

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

C.       BASIS OF ACCOUNTING FOR RATE-REGULATED SUBSIDIARIES. Statement of
         Financial Accounting Standards No. 71, "Accounting for the Effects of
         Certain Types of Regulation" (SFAS No. 71), provides that
         rate-regulated public utilities account for and report assets and
         liabilities consistent with the economic effect of the way in which
         regulators establish rates, if the rates established are designed to
         recover the costs of providing the regulated service and if the
         competitive environment makes it probable that such rates can be
         charged and collected. Columbia's transmission and gas distribution
         subsidiaries 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.

         In Columbia Gas of Ohio, Inc.'s (Columbia of Ohio) 1999 rate agreement
         (See Note 2), the Public Utilities Commission of Ohio (PUCO) authorized
         Columbia of Ohio to revise its depreciation accrual rates for the
         period January 1, 1999 through December 31, 2004. The revised
         depreciation rates are lower than those which would have been utilized
         if Columbia of Ohio were not subject to regulation. The amount of
         depreciation that would have been recorded for 2000 had Columbia of
         Ohio not been subject to rate regulation is $34.5 million, a $21.1
         million increase over the $13.4 million reflected in rates.
         Accordingly, a regulatory asset has been established in the amount of
         $39.9 million at December 31, 2000.

         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)                                              2000        1999        2000        1999
-------------------------------------------------------------------------------------------------------------------------
<S>                                                                         <C>         <C>          <C>         <C>
ASSETS
 Environmental costs                                                         78.3        95.5          4.5         5.0
 Postemployment and postretirement benefits costs                            52.3        56.2         97.3       105.5
 Percent of income plan receivables                                             -           -          6.4         8.0
 Retirement income plan costs                                                 9.2        12.7         11.9        14.9
 Regulatory effects of accounting for income taxes                              -           -         77.0        64.4
 Post in-service carrying charges                                               -           -         15.3        16.0
 Underrecovered gas costs                                                       -           -        169.0        40.5
 Depreciation                                                                   -           -         39.9        18.8
 Other                                                                        6.8         7.9         10.3         5.9
-------------------------------------------------------------------------------------------------------------------------
TOTAL REGULATORY ASSETS                                                     146.6       172.3        431.6       279.0
-------------------------------------------------------------------------------------------------------------------------
LIABILITIES
 Rate refunds and reserves                                                      -         5.3          6.8        16.1
 Overrecovered gas costs                                                        -           -            -        14.6
 Regulatory effects of accounting for income taxes                           13.4        15.2         19.2        21.0
 Other                                                                        6.4        23.1          2.0         2.0
------------------------------------------------------------------------------------------------------------------------
TOTAL REGULATORY LIABILITIES                                                 19.8        43.6         28.0        53.7
------------------------------------------------------------------------------------------------------------------------
</TABLE>

         Regulatory assets of approximately $428.3 million are not presently
         included in the rate base and consequently are not earning a return on
         investment. These regulatory assets are being recovered through cost of
         service. The remaining recovery periods generally range from one to
         fifteen years. Regulatory assets of approximately $57.3 million require
         specific rate action. All regulatory assets are probable of recovery.

                                       35
<PAGE>   36
ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA  (continued)


         D. GAS UTILITY AND OTHER PLANT AND RELATED DEPRECIATION. Property,
         plant and equipment (principally utility plant) are stated at 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 2000 before-tax rates for AFUDC and IDC
         were 6.84% and 6.82%, respectively. The 1999 and 1998 before-tax rates
         for AFUDC were 5.91% and 7.43%, respectively, and for IDC were 6.94%
         and 6.96%, 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 2.4% in 2000, 1999 and 1998.
         The average annual depreciation rate for the distribution subsidiaries'
         property was 2.8% in 2000 and in 1999, and 3.1% in 1998.

         E. GAS AND OIL PRODUCING PROPERTIES. Columbia's subsidiaries engaged in
         exploring for and developing gas and oil reserves follow the full cost
         method of accounting. Under this method of accounting, all productive
         and nonproductive costs directly identified with acquisition,
         exploration and development activities including certain payroll and
         other internal costs are capitalized. Depletion 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.

         F. INTANGIBLE ASSETS. Intangible assets are recorded at original cost
         and are amortized on a straight line basis. Goodwill represents the
         excess of the purchase price over the fair value of net assets acquired
         and is being amortized over 40 years.

         Customer lists are being amortized over periods of 10 to 20 years.
         Intangible assets are immaterial to the consolidated financial
         statements.

         G. ACCOUNTING FOR RISK MANAGEMENT ACTIVITIES. Columbia's exploration
         and production subsidiary is exposed to market risk due primarily to
         fluctuations in commodity prices. In order to help minimize this risk,
         Columbia has adopted a policy that provides for the use of commodity
         derivative instruments to help ensure stable cash flow, favorable
         prices and margins. 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. The hedging objectives include assurance
         of stable and known cash flows, fixing favorable prices and margins
         when they become available.

         Columbia's exploration and production company utilize commodity price
         swaps and basis swaps. 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.

         Margin requirements for natural gas are also recorded as current
         assets. Unrealized gains and losses on all futures contracts are
         deferred on the consolidated balance sheets as either current assets or
         other deferred credits. Realized gains and losses from the settlement
         swaps are included in revenues concurrent with the associated physical
         transaction. The cash flows from commodity hedging are included in
         operating activities in the consolidated statements of cash flows.

         Columbia's exploration and production company is exposed to credit
         losses in the event of nonperformance by the counterparties to its
         various financial contracts. Management has evaluated such risk and
         believes that overall business risk is significantly reduced as these
         financial contracts are primarily with major investment grade financial
         institutions or their affiliates.

         Columbia utilizes fixed-to-floating interest rate swap agreements to
         modify the interest characteristics of a portion of its outstanding
         long-term debt. The differentials between amounts received and paid
         under the agreements are recorded as adjustments to interest expense.


                                       36
<PAGE>   37
ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA  (continued)

         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, 2000, over the
         carrying value is approximately $529.7 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.

         L. REVENUE RECOGNITION. Columbia's gas distribution subsidiaries bill
         customers on a monthly cycle billing basis. Revenues are recorded on
         the accrual basis and include an estimate for gas delivered but
         unbilled at the end of each accounting period. Cash received in advance
         from sales of commodities to be delivered in the future is deferred and
         recognized as income upon delivery of the commodity.

         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 probable through the regulatory process.

         N. ACCOUNTS RECEIVABLE SALES PROGRAM. Columbia enters into agreements
         with third parties to sell certain accounts receivable without
         recourse. These sales are reflected as reductions of accounts
         receivable in the accompanying consolidated balance sheets and as
         operating cash flows in the accompanying consolidated statements of
         cash flows. The costs of this program, which are based upon the
         purchasers' level of investment and borrowing costs, are charged to
         other income in the accompanying consolidated statements of income.

         O. 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.

2.       REGULATORY MATTERS

         In 1993, the Federal Energy Regulatory Commission (FERC) directed
         Columbia Gulf to show cause as to why it had not sought FERC
         abandonment authorization to reduce capacity on its mainline facility.
         In an August 8, 1997 order, the FERC approved a settlement between
         Columbia Gulf and FERC's enforcement staff requiring 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. In orders issued in December 1998 and 1999, the FERC has
         rejected challenges to the settlement and denied rehearing. In its
         order issued December 22, 1999, the FERC affirmed the validity of the
         1997 open

                                       37
<PAGE>   38
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

season but indicated that an additional open season in compliance with the
settlement will be necessary. In early February 2000, several appeals of the
FERC's orders in this proceeding were filed.

Columbia Gulf filed an application with the FERC on June 5, 1998, for authority
to increase the maximum certificated capacity of its mainline facilities. The
expansion project, referred to as Mainline `99, increased Columbia Gulf's
certificated capacity to nearly 2.2 Bcf/day, by replacing certain compressor
units and increasing the horsepower capacity of other compressor stations.
Various shippers contracted for the additional service through an open bidding
process held in late 1997 and early 1998. On February 10, 1999, the FERC issued
an order approving Columbia Gulf's June 1998 filing and construction commenced
on March 3, 1999. On March 12, 1999, requests for rehearing of the FERC order
were filed by three parties. On January 31, 2000, the FERC issued an order
denying the requests for rehearing and validating the open season held in
conjunction with Mainline `99. Appeals challenging the FERC's authorization of
the Mainline `99 facilities have been filed and are pending before the United
States Court of Appeals for the District of Columbia.

Columbia Transmission's rate case settlement, approved by the FERC in April
1997, provided for a hearing in the fall of 1998 to address environmental cost
recovery that was excluded from the settlement. As a result of settlement
discussions, the active parties reached an agreement on the overall components
of an environmental settlement. The comprehensive agreement includes such major
components as Columbia Transmission's total allowed recovery of environmental
remediation program costs and the disposition of any proceeds received by
Columbia Transmission from insurance carriers and others. Columbia Transmission
filed the stipulation and agreement with the FERC on April 5, 1999 and on
September 15, 1999, the FERC approved the settlement. No requests for rehearing
were filed. The approval of the settlement did not have a material impact on
Columbia's consolidated financial results.

The distribution subsidiaries (Distribution) continue to pursue initiatives that
give retail customers the opportunity to purchase natural gas directly from
marketers and to use Distribution's facilities for transportation services.
These opportunities are being pursued through regulatory initiatives in all of
its jurisdictions, which resulted in transportation programs being initiated in
all five of its service areas. Once fully implemented, these programs would
reduce Distribution's merchant function and provide all customer classes with
the opportunity to obtain gas supplies from alternative merchants. As these
programs expand to all customers, regulations will have to be implemented to
provide for the recovery of transition capacity costs and other transition costs
incurred by a utility serving as the supplier of last resort if the marketing
company cannot supply the gas. Transition capacity costs are created as
customers enroll in these programs and purchase their gas from other suppliers,
leaving Distribution with pipeline capacity it has contracted for but no longer
needs. The state commissions in Distribution's five jurisdictions are at various
stages in addressing these issues and other transition considerations.
Distribution is currently recovering, or has the opportunity to recover, the
costs resulting from the unbundling of its services and believes that most of
such future costs and costs resulting from being the supplier of last resort
will be mitigated or recovered.

On October 25, 1999, Columbia of Ohio and a group comprising diverse interested
parties, also known as the Collaborative, filed with the Public Utilities
Commission of Ohio (PUCO) a third amendment to its 1994 rate case. The filing,
which was approved by the PUCO on December 2, 1999, extends Columbia of Ohio's
CHOICE(SM) program through October 31, 2004, freezes base rates through October
31, 2004 and resolves the issue of transition capacity costs. Under the
agreement, Columbia of Ohio would assume total financial risk for mitigation of
transition capacity costs at no additional cost to customers. Among other items,
Columbia of Ohio would have the opportunity to utilize non-traditional revenue
sources as a means of offsetting the costs.

3. NiSOURCE ACQUISITION

On November 1, 2000, NiSource Inc. (NiSource) completed its acquisition of
Columbia for an aggregate consideration of approximately $6 billion, primarily
consisting of 72.4 million shares of common stock valued at $1,761 million, with
the remaining approximately $3,888 million paid in cash and Stock Appreciation
Income Linked Securities(SM), referred to as SAILS(SM), (units each consisting
of zero coupon debt security coupled with a forward equity contract) valued at
$114 million. NiSource also assumed approximately $2 billion in Columbia debt.
As part of the Merger Agreement, the stock options under Columbia's Long-Term
Incentive Plans were cancelled. The holders of the stock options received
approximately $120.6 million from the cash-out of the stock options. The
acquisition of Columbia by NiSource triggered change in control payments of
approximately $44.5 million under certain employment agreements. The cost of the
cash-out of the stock options and the change of control payments of
approximately $155.9 million were charged to expense in the fourth quarter of
2000. As provided for in the Merger Agreement, NiSource organized a new company
that will serve as the holding company for Columbia and its subsidiaries.

                                       38
<PAGE>   39
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

4. RESTRUCTURING ACTIVITIES

During 2000, Columbia developed and began the implementation of a plan to
restructure its operations as a result of the acquisition of Columbia by
NiSource, discussed above. The restructuring plan included a severance program,
a transition plan to implement operational efficiency throughout NiSource's
operations and a voluntary early retirement program (See Note 10).

As a result of the restructuring plan, it is estimated that approximately 781
management, professional, administrative and technical positions have been or
will be eliminated. In October 2000, Columbia recorded pre-tax charges of $66.9
million in operating expense representing restructuring costs. This charge
included $47.5 million for severance and related benefits, $10.8 million for
costs to terminate leases and $8.6 million for relocation costs. As of December
31, 2000, approximately 288 employees had been terminated as a result of the
restructuring plan. At December 31, 2000, the consolidated balance sheet
reflected an accrual of $61.7 million related to the restructuring plan.

5. DISCONTINUED OPERATIONS

On May 22, 2000, as a result of its ongoing strategic assessment, Columbia
announced that it decided to sell Columbia Propane Corporation (Columbia
Propane), a propane marketer. Columbia also announced its decision to sell
Columbia Petroleum Corporation (Columbia Petroleum), a diversified petroleum
distribution company. On January 31, 2001, Columbia signed a definitive
agreement to sell the stock and assets of Columbia Propane to AmeriGas Partners
L.P. (AmeriGas) for approximately $208 million, including $53 million of
AmeriGas partnership common units. The transaction is expected to close in the
second quarter of 2001. Columbia Propane and Columbia Petroleum are reported as
discontinued operations and therefore the financial statements for prior periods
have been reclassified accordingly.

In the third quarter 2000, Columbia sold its Retail Mass Marketing business to
The New Power Company. The proceeds from the sale were $44.2 million. Columbia
Energy Services ceased operations of its Major Accounts business during the
third quarter of 2000. Columbia Energy Services' Wholesale and Trading
operations, Major Accounts and Retail Mass Markets businesses are reported as
discontinued operations and at December 31, 2000, have essentially ceased all
operations.

The revenues from discontinued operations were $867.4 million (Gas $187 million,
Power Trading $12.2 million, Propane $331 million, Petroleum $300.5 million and
Other $36.7 million) and $5,761.8 million (Gas $4,433.3 million, Power Trading
$1,021 million, Propane $152.9 million, Petroleum $127.7 million and Other $26.9
million) and $4,139.1 million (Gas $3,504.1 million, Power Trading $564.4
million, Propane $63.1 million and Other $7.5 million) for the years ended
December 31, 2000, December 31, 1999 and December 31, 1998, respectively. The
loss from discontinued operations and the estimated loss on disposal information
are provided in the following table:

<TABLE>
<CAPTION>
($ in millions)                                     2000       1999        1998
================================================================================
<S>                                               <C>         <C>         <C>
Loss from discontinued operations                   (2.0)     (175.9)     (61.1)
Income tax benefit                                  (0.5)      (63.1)     (21.4)
--------------------------------------------------------------------------------
NET LOSS FROM DISCONTINUED OPERATIONS               (1.5)     (112.8)     (39.7)
--------------------------------------------------------------------------------
Estimated loss on disposal                        (226.6)      (39.5)      --
Income tax benefits                                (67.2)      (13.7)      --
--------------------------------------------------------------------------------
NET ESTIMATED LOSS ON DISPOSAL                    (159.4)      (25.8)      --
--------------------------------------------------------------------------------
</TABLE>

The net assets of the discontinued operations were as follows:

<TABLE>
<CAPTION>
($ in millions)                                                2000       1999
===============================================================================
<S>                                                          <C>         <C>
NET ASSETS OF DISCONTINUED OPERATIONS
   Accounts receivable, net                                    91.3       416.7
   Property, Plant and Equipment, net                         212.2       212.0
   Other assets                                                70.2       239.6
   Accounts payable                                           (68.3)     (388.4)
   Other liabilities                                          (69.1)      (69.9)
--------------------------------------------------------------------------------
NET ASSETS OF DISCONTINUED OPERATIONS                         236.3       410.0
--------------------------------------------------------------------------------
</TABLE>

                                       39
<PAGE>   40
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

6. COMMON STOCK EQUITY

A. STOCK SPLIT EFFECTED IN THE FORM OF A STOCK DIVIDEND. On May 20, 1998,
Columbia's Board of Directors (Columbia's Board) approved a three-for-two common
stock split, effected in the form of a 50% stock dividend (stock split), on June
15, 1998, payable to shareholders of record as of June 1, 1998. In connection
with the stock split, 27.8 million shares were issued on June 15, 1998, and
$277.9 million was transferred to common stock from retained earnings. The value
of fractional shares resulting from the stock split was determined at the
closing price on June 1, 1998, and $0.6 million was paid in cash to the
shareholders for fractional-share interests. All references in the financial
statements and notes to the number of common shares outstanding except where
otherwise noted, reflect the retroactive effect of the stock split.

B. TREASURY STOCK. In March 2000, Columbia announced that it had restarted its
open market share repurchase program, that was authorized by Columbia's Board.
Under the recommenced program, Columbia was allowed to repurchase up to $300
million of its common shares through July 14, 2000. The repurchase program
authorized Columbia to make purchases in the open market or otherwise. The
timing and terms of purchases, and the number of shares actually purchases, were
determined by management based on several factors including market conditions.
Purchased shares were held in treasury at cost and were available for general
corporate purposes, resale or retirement. During 2000, Columbia purchased
1,889,800 common shares at a cost of $114.1 million under the recommenced
program. As of July 14, 2000, Columbia had purchased 4,368,300 common shares at
a cost of $249.1 million. In November 2000, as part of the merger of Columbia
with NiSource, the Treasury Stock was retired.

C. COMMON STOCK - AMENDMENTS. At Columbia's Annual Meeting of Shareholders held
on May 19, 1999, the shareholders voted to approve an amendment of Columbia's
Restated Certificate of Incorporation to increase the authorized number of
shares of common stock from 100 million to 200 million and decrease the par
value of common stock from $10 to $.01 per share. This change resulted in a
transfer during the second quarter of 1999 of $834.3 million from Common Stock
to Additional Paid In Capital.

7. RISK MANAGEMENT ACTIVITIES

Columbia's exploration and production subsidiary is exposed to market risk due
primarily to fluctuations in commodity prices. In order to help minimize this
risk, Columbia has adopted a policy that provides for commodity hedging
activities to help ensure stable cash flow, favorable prices and margins.
Financial instruments authorized for use by Columbia for hedging include
futures, swaps and options.

Columbia's exploration and production subsidiary hedged a portion of its gas
production that was subject to price volatility. At December 31, 2000, there
were 7,676 open contracts representing a notional quantity amounting to 67.3 Bcf
of commodity contracts for natural gas production through December 2002 at an
average price of $3.66 per Mcf. Also at December 31, 2000, there were 23,009
open contracts representing a notional quantity amounting to 201.8 Bcf of basis
contracts through 2005 at an average price of $.22 per Mcf. A total of $188.6
million of unrealized losses were deferred on the consolidated balance sheets
with respect to these open contracts. During the year ended December 31, 2000,
$44.2 million of losses were realized on contracts settled. At December 31,
1999, there were 4,214 open contracts representing a notional quantity amounting
to 6.6 Bcf of commodity contracts and 30.4 Bcf of basis contracts for natural
gas production through February and October 2000, respectively at a combined
average price of $3.61 per Mcf. A total of $6.1 million of unrealized gains had
been deferred on the consolidated balance sheets, at December 31, 1999, with
respect to these open contracts. During the year ended December 31, 1999, $0.5
million of losses were realized on contracts settled.

8. NEW ACCOUNTING STANDARDS

A. In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" (SFAS No. 133). This statement, as amended, establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, (collectively referred to as
derivatives) and for hedging activities. SFAS No. 133 requires an entity to
recognize all derivatives as either assets or liabilities in the balance sheet
and measure those instruments at fair value. If certain conditions are met, a
derivative may be specifically designated as (a) a hedge of the exposure to
changes in the fair value of a recognized asset or liability or an unrecognized
firm commitment, (b) a hedge of the exposure to variable cash flows of a
forecasted transaction, or (c) a hedge of the foreign currency exposure of a net
investment in a foreign-currency-denominated forecasted transaction. The
accounting for changes in the fair value of a derivative depends on the intended
use of the

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

derivative and resulting designation. A company may implement SFAS No. 133 as of
the beginning of any fiscal quarter, however the statement cannot be applied
retroactively.

The adoption of this statement on January 1, 2001, is estimated to result in a
cumulative after-tax increase to net income of approximately $5 million and an
after-tax reduction to other comprehensive income of approximately $35 million.
The adoption is also estimated to result in approximately $165 million of
derivatives to be recognized on the consolidated balance sheet as assets and
approximately $210 million of derivatives to be recognized as liabilities.

B. In September 2000, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 140, "Accounting for Transfers and
Servicing of Financial Assets and Extinguishment of Liabilities, a Replacement
of FASB Statement No. 125" (SFAS No. 140). This statement replaces FASB
Statement No. 125, "Accounting for Transfers and Servicing of Financial Assets
and Extinguishments of Liabilities." It revises the standards for accounting for
securitizations and other transfers of financial assets and collateral and
requires certain disclosures, but it carries over most of Statement 125's
provisions without reconsideration.

This statement provides accounting and reporting standards for transfers and
servicing of financial assets and extinguishments of liabilities. Those
standards are based on consistent application of a financial-components approach
that focuses on control. Under that approach, after a transfer of financial
assets, an entity recognizes the financial and servicing assets it controls and
the liabilities it has incurred, derecognizes financial assets when control has
been surrendered, and derecognizes liabilities when extinguished. This Statement
provides consistent standards for distinguishing transfers of financial assets
that are sales from transfers that are secured borrowings. This statement has no
new impact on Columbia's current accounts receivable sales program.

C. In December 1999, the SEC issued Staff Accounting Bulletin (SAB) No. 101,
"Revenue Recognition in Financial Statements." This SAB summarized certain of
the SEC Staff's views in applying generally accepted accounting principles to
revenue recognition in financial statements. In June 2000, the SEC issued SAB
No. 101B, which delayed the implementation of SAB No. 101 until no later than
the fourth fiscal quarter of fiscal years beginning after December 15, 1999. The
adoption of this SAB did not have a material effect on Columbia's financial
statements.


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

9. INCOME TAXES

The components of income tax expense are as follows:

<TABLE>
<CAPTION>
Year Ended December 31, ($ in millions)                 2000        1999       1998
=====================================================================================
<S>                                                    <C>         <C>         <C>
INCOME TAXES
Current
     Federal                                            63.4       125.7       114.5
     State                                               7.4         4.8         2.0
-------------------------------------------------------------------------------------
Total Current                                           70.8       130.5       116.5
-------------------------------------------------------------------------------------
Deferred
     Federal                                           102.0        71.4        50.8
     State                                              19.0       (22.3)      (13.6)
-------------------------------------------------------------------------------------
Total Deferred                                         121.0        49.1        37.2
-------------------------------------------------------------------------------------
Deferred Investment Credits                             (1.4)       (1.5)       (1.5)
-------------------------------------------------------------------------------------
Income Taxes Included in Continuing Operations         190.4       178.1       152.2
-------------------------------------------------------------------------------------
Income Taxes Related to Discontinued Operations        (67.7)      (76.8)      (21.4)
-------------------------------------------------------------------------------------
TOTAL INCOME TAXES                                     122.7       101.3       130.8
-------------------------------------------------------------------------------------
</TABLE>

Total income taxes from continuing operations 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)                               2000               1999                1998
======================================================================================================================
<S>                                                           <C>        <C>       <C>       <C>       <C>       <C>
Income before income taxes from continuing operations         485.0                565.9               461.1
Tax expense at statutory Federal income tax rate              169.8      35.0%     198.1     35.0%     161.4     35.0%
Increases (reductions) in taxes resulting from:
  State income taxes, net of Federal income tax benefit        17.2       3.6      (11.4)    (2.0)      (7.5)    (1.6)
  Estimated non-deductible expenses                            17.5       3.6        1.4      0.2        1.6      0.3
  Effect of change in deferred taxes previously provided       (3.3)     (0.7)      (3.5)     1.5        0.3     (0.6)
  Other                                                       (10.8)     (2.2)      (6.5)    (1.1)      (4.8)    (1.0)
-----------------------------------------------------------------------------------------------------------------------
INCOME TAXES FROM CONTINUING OPERATIONS                       190.4      39.3%     178.1     31.5%     152.2     33.0%
-----------------------------------------------------------------------------------------------------------------------
</TABLE>

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)                                       2000      1999
======================================================================================
<S>                                                                 <C>       <C>
Deferred tax liabilities
   Property basis differences                                        768.9     728.1
   Gas purchase costs                                                 80.1      47.6
   Investment in Partnerships                                          2.9       5.4
   Other                                                              33.5      28.1
--------------------------------------------------------------------------------------
Gross Deferred Tax Liabilities                                       885.4     809.2
--------------------------------------------------------------------------------------
Deferred tax assets
   Estimated rate refunds                                             (5.9)    (12.7)
   Inventory                                                         (15.9)    (16.3)
   Benefit plan accruals                                              (7.2)    (12.5)
   Environmental liabilities                                          (7.1)    (14.2)
   State tax loss carryforwards                                      (33.6)    (43.7)
   Deferred revenue                                                   (6.0)    (20.8)
   Other                                                             (32.9)    (57.0)
--------------------------------------------------------------------------------------
Gross Deferred Tax Assets                                           (108.6)   (177.2)
--------------------------------------------------------------------------------------
Deferred Tax Asset Valuation Allowance                                 7.7      11.4
--------------------------------------------------------------------------------------
TOTAL NET DEFERRED TAX LIABILITY                                     784.5     643.4
--------------------------------------------------------------------------------------
Deferred income taxes related to current assets and liabilities      (17.7)     18.5
--------------------------------------------------------------------------------------
Deferred Income Taxes-Noncurrent                                     766.8     661.9
--------------------------------------------------------------------------------------
</TABLE>


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

As reflected by the valuation allowance in the table above, Columbia had
potential tax benefits of $7.7 million and $11.4 million at December 31, 2000,
and 1999, respectively, which were not recognized in the statements of
consolidated income when generated. These benefits result primarily from state
income tax operating loss carryforwards which are available to reduce future tax
liabilities. The net decrease of $3.7 million in the valuation allowance
reflects realization of state income tax carry forward benefits upon the sale of
certain assets. The expiration of the tax loss carryforward benefits, net of
federal taxes, in 2001 is $0.1 million, in 2002 is $0.1 million, in 2003 is $0.1
million, in 2004 is $0.1 million, in 2005 is $0.1 million and beyond is $33.1
million.

10. PENSION AND OTHER POSTRETIREMENT BENEFITS

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. Effective January 1, 2000, Columbia adopted a cash
balance feature to the pension plan that provides benefits based on a
percentage, which may vary with age and years of service, of current eligible
compensation and current interest credits. Columbia's funding policy complies
with Federal law and tax regulations. In addition, Columbia has a nonqualified
pension plan that provides benefits to some employees in excess of the qualified
plan's Federal tax limits. 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. Columbia is reflecting the information presented below as of
September 30, rather than December 31. The effect of utilizing September 30,
rather than December 31, is not significant.

During 2000, Columbia announced the introduction of a voluntary incentive
retirement program (VIRP). Approximately 1,880 employees were eligible for the
VIRP, which provides a retirement incentive for active employees who were age
fifty and above with at least five years of service as of certain
retirement-window dates. During the acceptance periods, approximately 1,337
employees elected early retirement. The majority of the retirements occurred
during 2000. The VIRP resulted in special termination benefits of $59.3 million
and curtailment losses of $47.7 million. The curtailment losses were offset by
previously unrecognized actual gains. As a result of the VIRP, Columbia
recognized $35.7 million of net settlement gains.

On October 13, 2000, the Columbia Retirement Board determined that, under the
terms of the Retirement Plan of Columbia Energy Group Companies (The Plan), a
partial plan termination had occurred. As a result, participants in the Plan
will be granted additional vesting service if they have terminated or will
terminate their employment with Columbia Energy Group or any of its subsidiaries
between January 1, 1999 and June 30, 2001. Employees who have terminated or will
terminate employment during this time period with less than 5 years of plan
participation will be 100% vested in the Plan as of their date of termination.
As a result, Columbia recorded additional expense of approximately $3.1 million
in October 2000.

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

The following tables provide a reconciliation of the plans' funded status and
amounts reflected in Columbia's consolidated balance sheets at December 31:

<TABLE>
<CAPTION>
                                                       PENSION BENEFITS     OTHER BENEFITS

($ in millions)                                        2000        1999     2000      1999
=============================================================================================
<S>                                                  <C>        <C>        <C>       <C>
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year               883.8       946.8     182.2     198.9
Service cost                                           29.5        30.6      11.1      12.6
Interest cost                                          65.0        62.9      16.6      14.0
Plan participants' contributions                         --          --       2.6       2.4
Plan amendments                                          --         3.9        --       4.5
Actuarial (gain) loss                                  13.3       (59.8)    (10.5)    (12.2)
Partial plan termination                                3.1          --        --        --
Curtailments                                           47.7          --      35.4        --
Settlements                                          (269.2)         --        --     (24.5)
Special termination benefits                           59.3          --      31.9        --
Actual expense paid                                    --          (4.7)       --        --
Benefits paid                                         (55.9)      (95.9)     (9.3)    (13.5)
---------------------------------------------------------------------------------------------
Benefit obligation at end of year                     776.6       883.8     260.0     182.2
---------------------------------------------------------------------------------------------

CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year      1,201.1     1,091.5     115.8     117.0
Actual return on plan assets                          135.7       210.0      13.6      26.0
Columbia contributions                                  0.4          --      17.5      15.5
Plan participants' contributions                         --          --       2.6       2.4
Settlements                                          (269.2)         --        --     (31.6)
Actual expense paid                                    --          (4.7)       --        --
Benefits paid                                         (55.9)      (95.7)     (9.2)    (13.5)
---------------------------------------------------------------------------------------------
Fair value of plan assets at end of year            1,012.1     1,201.1     140.3     115.8
---------------------------------------------------------------------------------------------

Funded status of plan at end of year                  235.5       317.3    (119.7)    (66.4)
Unrecognized actuarial net gain                      (266.8)     (403.4)    (32.3)    (54.1)
Unrecognized prior service cost                        41.3        45.2       2.4       2.6
Unrecognized transition obligation                      2.3         3.5        --        --
Fourth quarter contributions                            0.4          --       7.0       3.3
---------------------------------------------------------------------------------------------
PREPAID (ACCRUED) BENEFIT COST                         12.7       (37.4)   (142.6)   (114.6)
---------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
                                                        PENSION BENEFITS      OTHER BENEFITS
                                                        ----------------      --------------
                                                        2000       1999      2000       1999
=============================================================================================
<S>                                                    <C>         <C>       <C>       <C>
WEIGHTED-AVERAGE ASSUMPTIONS AS OF
  SEPTEMBER 30,
Discount rate assumption                               8.00%       7.75%     8.00%     7.75%
Compensation growth rate assumption                    4.50%       4.50%     4.50%     4.50%
Medical cost trend assumption                            --          --      5.50%     5.50%
Assets earnings rate assumption                        9.00%       9.00%     9.00%*    9.00%*
---------------------------------------------------------------------------------------------
</TABLE>

* One of the several established medical trusts and the trust established for
life insurance are subject to taxation which results in an after-tax asset
earnings rate that is less than 9.00%


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

The following table provides the components of the plans expense for each of the
three years:

<TABLE>
<CAPTION>
                                                     PENSION BENEFITS            OTHER BENEFITS

($ in millions)                                  2000     1999    1998      2000     1999     1998
====================================================================================================
<S>                                             <C>      <C>      <C>       <C>      <C>     <C>
NET PERIODIC COST
Service cost                                     29.5     30.6     31.3     11.1     12.6     13.0
Interest cost                                    65.0     62.9     64.7     16.6     14.0     23.5
Expected return on assets                       (98.0)   (94.1)   (99.7)    (7.7)    (9.4)   (18.3)
Amortization of transition obligation             1.2      1.2      1.2       --       --       --
Recognized gain                                 (18.3)   (10.2)   (17.5)    (1.7)    (2.1)   (10.3)
Prior service cost amortization                   3.9      3.7      3.7      0.2     (0.4)      --
Special charge for partial plan termination       3.1       --       --       --       --       --
Special termination benefit charge               59.3       --       --     31.9       --       --
Settlement gain                                 (95.0)      --       --       --     (6.1)   (46.6)
----------------------------------------------------------------------------------------------------
NET PERIODIC BENEFITS COST (BENEFIT)            (49.3)    (5.9)   (16.3)    50.4      8.6    (38.7)
----------------------------------------------------------------------------------------------------
</TABLE>

Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plans. A one-percentage-point change in assumed
health care cost trend rates would have the following effects:

<TABLE>
<CAPTION>
                                                                               1% point     1% point
                                                                               increase     decrease
=====================================================================================================
<S>                                                                            <C>          <C>
Effect on service and interest components of net periodic cost                   $ 2.9       $ (2.6)

Effect on accumulated postretirement benefit obligation                          $22.1       $(19.1)
-----------------------------------------------------------------------------------------------------
</TABLE>

During 1999 and 1998, Columbia and the trusts established by Columbia purchased
insurance policies that provide both medical and life insurance with respect to
liabilities to a selected class of current retirees. As a result, pre-tax gains
in the amount of $6.1 million and $46.6 million were recorded in 1999 and 1998,
respectively. The 1999 gain is reflected in the consolidated financial
statements as a $4 million reduction to benefits expense, and a $2.1 million
liability of certain rate-regulated companies. The 1998 gain is reflected in the
financial statements as a $25.4 million reduction to benefits expense, and a
$21.2 million liability of certain rate-regulated companies.

11. LONG-TERM DEBT

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

<TABLE>
<CAPTION>
At December 31,  ($ in millions)                                                 2000         1999
====================================================================================================
<S>                                                                            <C>          <C>
Columbia Energy Group Debentures
  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                                         229.2        229.2
----------------------------------------------------------------------------------------------------
Total Debentures                                                               1,636.7      1,636.7

Subsidiary Debt:
Capitalized lease obligations                                                      2.4          2.6
----------------------------------------------------------------------------------------------------
TOTAL LONG-TERM DEBT                                                           1,639.1      1,639.3
====================================================================================================
</TABLE>

In 1999, Columbia repurchased $52.45 million of its 7.62% Series G Debentures
due November 28, 2025 at a price of approximately 99% of par value. The net
impact of the early extinguishment of such debt was immaterial.

Columbia has entered into interest rate swap agreements to modify the interest
characteristics of its outstanding long-term debt. At December 31, 2000,
Columbia has outstanding four interest rate swap agreements effective through
November 28, 2002, on $200 million notional amounts of its 6.61% Series B
Debentures due November 28, 2002. In addition, Columbia has outstanding an
interest rate swap agreement effective through November 28, 2005,

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

on a $100 million notional amount of its 6.80% Series C Debentures due November
28, 2005. Under the terms of the agreements, Columbia pays interest based on a
floating rate index and receives interest based on a fixed rate. The effect of
these agreements is to modify the interest rate characterization of a portion of
Columbia's long-term debt from fixed to variable. The effect of these interest
rate swaps on interest expense in 2000 and 1999 was immaterial.

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>
2001                                                                        0.2
2002                                                                      281.7
2003                                                                        0.2
2004                                                                        0.3
2005                                                                      281.9
--------------------------------------------------------------------------------
</TABLE>

12. SHORT-TERM DEBT AND CREDIT FACILITIES

During 2000, Columbia had two unsecured bank revolving credit facilities
available that totaled $1.35 billion (Credit Facilities). On October 11, 2000,
the Credit Facilities were amended and restated, and decreased in aggregate to
$900 million. The existing $450 million 364-day facility was increased in size
to $850 million, and is scheduled to expire in October 2001. The existing $900
million five-year facility was decreased in size to $50 million, shortened to a
two-year facility expiring in October 2002, and will be solely used to support
the issuance of letters of credit. Interest rates on borrowings under the Credit
Facilities are based upon the London Interbank Offered Rate, Certificate of
Deposit rate or Citibank's publicly announced "base rate." In addition, the
Credit Facilities have a utilization fee if borrowings exceed a certain level.
Facility fees and borrowing margins are based on Columbia's public debt ratings.
The Credit Facilities contain certain covenants that must be met to borrow
funds, including restrictions on the incurrence of liens and a maximum leverage
ratio. Compensating balances are not required.

Columbia had no borrowings outstanding under the Credit Facilities at December
31, 2000, and December 31, 1999, respectively.

On October 28, 1999, Columbia issued a note payable outside of the Credit
Facilities in the amount of $125 million at an interest rate of 6.70%. The note
matured on January 28, 2000.

As of December 31, 2000, Columbia had $14.6 million of letters of credit
outstanding under the Credit Facilities. 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. In addition, Columbia had
approximately $34.6 million of letters of credit outstanding to guarantee
certain transactions of affiliates. Fees for the letter of credit issued were at
rates of 0.625% to 1.0%. At December 31, 1999, Columbia had $54.7 million of
letters of credit outstanding under the Credit Facilities.

Columbia has an $850 million commercial paper program authorized and rated by
the rating agencies. The commercial paper program is supported by the Credit
Facilities. At December 31, 2000, Columbia had commercial paper outstanding of
$521 million (net of discount) at a weighted-average interest rate of 7.76%. The
maximum commercial paper indebtedness outstanding during the year occurred on
December 5, 2000, in the amount $683.5 million at an average interest rate of
7.1%. At December 31, 1999, Columbia had commercial paper outstanding of $340.5
million (net of discount) at a weighted-average interest rate of 6.34%.

Columbia was the guarantor on certain transactions of its former affiliates that
were sold during 1999 and 2000. At December 31, 2000, Columbia had an $81.7
million letter of credit outstanding and has issued other guarantees and
indemnities in the amount of $741.3 million.

At December 31, 2000, approximately $14.5 million of investments were pledged as
collateral on outstanding letters of credit related to Columbia's wholly-owned
insurance company.

13. FAIR VALUE OF FINANCIAL INSTRUMENTS

Statement of Financial Accounting Standards No. 107, "Disclosures about Fair
Value of Financial Instruments," requires all entities to disclose the fair
value of financial instruments, both assets and liabilities, recognized and not

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

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 12) 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 ($5.8 million for 2000 and $7.7
million for 1999) 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 ($11.6 million for 2000 and $14.4
million for 1999), 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 $17.5 million and
$22.1 million, and estimated fair values of $17.2 million and $21.7 million at
December 31, 2000, and 1999, respectively. There are no long-term investments
for which it is not practicable to estimate fair value at December 31, 2000, and
1999.

LONG-TERM DEBT

The estimated fair value of Columbia's debentures, including current maturities
and accrued interest, is based on estimates provided by brokers. Long-term debt
of $1,647.4 million and $1,960.1 million at December 31, 2000, and 1999, have
estimated fair values of $1,586.7 million and $1,858.4 million, respectively.

The fair value of Columbia's interest rate swaps agreements are based on the
amounts estimated to terminate or settle the agreements. At December 31, 2000,
and December 31, 1999, Columbia had interest rate swaps agreements with notional
amounts of $300 million. Columbia would have paid $3.9 million and $18 million
to terminate the agreements at December 31, 2000, and December 31, 1999,
respectively.

ACCOUNTS RECEIVABLE SALES PROGRAM

In October 1999, Columbia of Ohio entered into an agreement to sell, without
recourse, substantially all of its trade accounts receivable to Columbia
Accounts Receivable Corporation (CARC), a wholly-owned subsidiary of Columbia.
At the same time, CARC entered into an agreement, with a third party, Canadian
Imperial Bank of Commerce (CIBC), to sell a percentage ownership interest in a
defined pool of accounts receivable (Sales Program). Under this Sales Program,
CARC can transfer an undivided interest in a designated pool of its accounts
receivable on an ongoing basis up to a maximum of $125 million until April 30,
2001, at which time the maximum decreases to $100 million. The amount available
at any measurement date varies based upon the level of eligible receivables.
Under this agreement, approximately $108 million of receivables were sold as of
December 31, 2000.

Under a separate agreement, in conjunction with the Sales Program, Columbia of
Ohio acts as agent for CIBC, the ultimate purchaser of the receivables, by
performing record keeping and cash collection functions for the accounts
receivable sold by CARC. Columbia of Ohio receives a fee, which provides
adequate compensation, for such services.

14. OTHER COMMITMENTS AND CONTINGENCIES

A. BANKRUPTCY MATTERS. On November 28, 1995, Columbia and its wholly-owned
subsidiary, Columbia Transmission emerged from Chapter 11 protection of the
United States 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 from July 31,
1991, until emergence. Certain residual unresolved bankruptcy-related matters
are still within the jurisdiction of the Bankruptcy Court.

B. CAPITAL EXPENDITURES. Capital expenditures for 2001 are currently estimated
at $379 million. Of this amount, $132 million is for transmission and storage
operations, $113 million for distribution operations, $132 million for
exploration and production operations and $2 million for other products and
services.

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

C. OTHER LEGAL PROCEEDINGS. In the normal course of its business, 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.

D. 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.

E. GUARANTEES AND INDEMNITIES. In connection with the purchase of National
Propane Partners, L.P. (National Propane) interests, Columbia has provided an
indemnity to reimburse the former Managing General Partner for income taxes that
would be due if certain actions by Columbia result in the recognition of certain
types of income or gain by the former Managing General Partner.

F. INTERNAL REVENUE SERVICE (IRS) AUDIT. All unagreed issues associated with the
audit of Columbia's 1995 federal income tax return have been settled with IRS
Appeals. The field audit of tax years 1996 and 1997, currently in progress, is
expected to be completed in 2001. Management believes adequate reserves have
been established for issues related to these returns.

G. OPERATING LEASES. Payments made in connection with operating leases are
primarily charged to operation and maintenance expense as incurred. Such amounts
were $71.6 million in 2000, $61.5 million in 1999 and $63.8 million in 1998.

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>
2001                                                                       23.5
2002                                                                       20.7
2003                                                                       20.4
2004                                                                       19.8
2005                                                                       19.3
After                                                                     159.3
--------------------------------------------------------------------------------
</TABLE>

H. PURCHASE COMMITMENTS. Columbia has service agreements that provide for
pipeline capacity, transportation and storage services. These agreements which
have expiration dates ranging from 2001 to 2014, provide for Columbia to pay
fixed monthly charges. The estimated aggregate amounts of such payments at
December 31, 2000, were:

<TABLE>
<CAPTION>
($ in millions)
================================================================================
<S>                                                                       <C>
2001                                                                       54.0
2002                                                                       49.7
2003                                                                       36.7
2004                                                                       33.0
2005                                                                       28.2
After                                                                     155.3
--------------------------------------------------------------------------------
</TABLE>

Costs incurred under these contracts are generally recovered under Columbia's
regulatory cost recovery mechanisms (See Note 2).

I. 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.

Columbia's transmission subsidiaries have implemented programs to continually
review compliance with existing environmental standards. In addition, the
transmission subsidiaries have reviewed past operational activities and
conducted remediation programs where necessary.

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

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). The program pursuant to the
AOC covers approximately 240 facilities, approximately 13,000 liquid removal
points, approximately 2,200 mercury measurement stations, and about 3,700
storage wells. As of December 31, 2000, field characterization has been
performed at many of these sites, and site characterization reports and
remediation plans which must be submitted to EPA for approval are in various
stages of development and completion. Significant remediation has taken place
only at mercury measurement stations and at a limited number of the 240
facilities.

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). As costs become probable and reasonably estimable,
the associated reserves will be adjusted as appropriate. Columbia Transmission
is unable, at this time, to accurately estimate the time frame and potential
costs of the entire program. Management expects that as additional work is
performed and more facts become available, it will 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.

During 2000, actual expenditures of $16.9 million were charged to the liability
resulting in a remaining liability at December 31, 2000, of $104.5 million.
Columbia Transmission's environmental cash expenditures are expected to be
approximately $17 million in 2001 and to remain at this level for the
foreseeable future. These expenditures will be charged against the previously
recorded liability. Consistent with Statement of Financial Accounting Standards
No. 71, a regulatory asset has been recorded to the extent environmental
expenditures are probable of recovery through rates. 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 time 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. As of the date of this report, Columbia Transmission is unable to
determine if it will become liable for any characterization or remediation costs
at such sites.

Distribution's primary environmental issues relate to 18 former manufactured gas
plant sites. Investigations or remedial activities are currently underway at six
sites and remedial construction has been completed at two sites. Additional site
investigations may be required at some of the remaining sites. To the extent
Distribution's site investigations have been conducted, remediation plans
developed and any responsibility for remediation established, the appropriate
estimated liabilities have been recorded. Regulatory assets have also been
recorded for a majority of these costs as rate recovery has been authorized or
is anticipated.

In spring 2000, Columbia Transmission Communication Corporation (Transcom)
received directives from The Philadelphia District of the U.S. Army Corps of
Engineers (Philadelphia District) and an administrative order from The
Pennsylvania Department of Environmental Protection (PA DEP) addressing alleged
violations of federal and state laws resulting from construction activities
associated with the Corporation's laying fiber optic cable along portions of a
route between Washington, D.C. and New York City. The order and directives
required Transcom to largely cease construction activities. On September 18,
2000, Transcom entered into a voluntary settlement agreement with the
Philadelphia District under which Transcom contributed $1.2 million to the
Pennsylvania chapter of the Nature Conservancy and the Philadelphia District
lifted its directives. As a result of the voluntary agreement with the
Philadelphia District and communications with the PA DEP, the Maryland
Department of the Environment and the Baltimore District of the US Army Corps of
Engineers, work in Pennsylvania and Maryland is now ongoing. Transcom cannot
predict the effect of the ongoing discussions on the completion schedule for the
project, nor the nature or amount of total remedies that may be sought in
connection with the foregoing construction activities.

Columbia Propane's primary environmental issues relate to former manufactured
gas plant sites acquired in the acquisition of National Propane for which
accruals have been made. Investigations are currently underway at one site. One
other known former manufactured gas plant site is inactive. It is possible that
former manufactured gas plant sites exist at two other National Propane
properties. Management does not believe that Columbia Propane's environmental
expenditures will have a material adverse effect on Columbia's consolidated
financial results.

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

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

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
$106.4 million for Columbia at December 31, 2000. As new issues are identified,
additional liabilities will be recorded.

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

15. INTEREST INCOME AND OTHER, NET

<TABLE>
<CAPTION>
Year Ended December 3l, ($ in millions)                   2000     1999    1998
================================================================================
<S>                                                      <C>       <C>     <C>
Interest income                                           22.8     20.0    14.7
Gain on sale of assets                                   221.0       --      --
Miscellaneous                                             (7.5)    14.9      --
--------------------------------------------------------------------------------
TOTAL INTEREST INCOME AND OTHER, NET                     236.3     34.9    14.7
--------------------------------------------------------------------------------
</TABLE>

16. INTEREST EXPENSE AND RELATED CHARGES

<TABLE>
<CAPTION>
Year Ended December 31, ($ in millions)                2000      1999     1998
================================================================================
<S>                                                   <C>       <C>       <C>
Interest on debentures                                134.6     138.0     140.4
Interest on short-term debt                            26.3      18.2      10.5
Discount on prepayment transactions                    22.6       2.3        --
Interest on rate refunds                                0.6       3.1       2.3
Interest on prior years' taxes                        (11.5)      6.2      (6.3)
Allowance for borrowed funds used
  and interest during construction                     (3.0)     (3.6)     (2.7)
--------------------------------------------------------------------------------
TOTAL INTEREST EXPENSE AND RELATED CHARGES            169.6     164.2     144.2
--------------------------------------------------------------------------------
</TABLE>

17. BUSINESS SEGMENT INFORMATION

Columbia is a registered holding company under the Public Utility Holding
Company Act of 1935, as amended, and derives substantially all of its revenues
and earnings from the operating results of its 19 direct subsidiaries. During
2000, Columbia revised the presentation of its business segments and, in
accordance with generally accepted accounting principles, all prior periods have
been restated. Columbia's operations are divided into four primary business
segments. The transmission and storage segment offers transportation and storage
services for local distribution companies, marketers and industrial and
commercial customers located in northeastern, mid-Atlantic, midwestern and
southern states and the District of Columbia. The distribution segment provides
natural gas service and transportation for residential, commercial and
industrial customers in Ohio, Pennsylvania, Virginia, Kentucky and Maryland. The
exploration and production segment explores for, develops, produces and markets
gas and oil in the United States and in Canada. The other products and services
segment primarily engages in the construction of a dark-fiber optics
telecommunications network along its pipeline rights-of-way between Washington,
D.C. and New York City.

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

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.

<TABLE>
<CAPTION>
($ in millions)                                   2000        1999        1998
================================================================================
<S>                                             <C>         <C>         <C>
REVENUES
    Transmission and Storage
      Unaffiliated                                607.8       571.5       546.0
      Intersegment                                248.0       264.9       292.7
--------------------------------------------------------------------------------
      TOTAL                                       855.8       836.4       838.7
--------------------------------------------------------------------------------
    Distribution
      Unaffiliated                              2,037.9     2,021.9     1,868.5
      Intersegment                                 (2.0)        0.9         1.0
--------------------------------------------------------------------------------
      TOTAL                                     2,035.9     2,022.8     1,869.5
--------------------------------------------------------------------------------
    Exploration and Production
      Unaffiliated                                176.5       143.4       125.4
      Intersegment                                  2.0         1.4         2.1
--------------------------------------------------------------------------------
      TOTAL                                       178.5       144.8       127.5
--------------------------------------------------------------------------------
    Other Products and Services
      Unaffiliated                                 49.9        96.7        23.3
      Intersegment                                  0.2        (0.4)       (0.1)
--------------------------------------------------------------------------------
      TOTAL                                        50.1        96.3        23.2
--------------------------------------------------------------------------------
    Corporate
      Unaffiliated                                 10.0        --          --
      Intersegment                               (247.0)     (266.8)     (295.7)
--------------------------------------------------------------------------------
      TOTAL                                      (237.0)     (266.8)     (295.7)
--------------------------------------------------------------------------------
    Transportation Costs*                         (24.3)      (32.6)      (17.1)
--------------------------------------------------------------------------------
    CONSOLIDATED                                2,859.0     2,800.9     2,546.1
--------------------------------------------------------------------------------
</TABLE>

*Transportation revenues on consolidated income statement were reduced by these
                                     costs.


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

<TABLE>
<CAPTION>
($ in millions)                                   2000        1999         1998
================================================================================
<S>                                            <C>         <C>         <C>
OPERATING INCOME (LOSS)
    Transmission and Storage                      264.9       350.1       326.1
    Distribution                                  176.0       254.6       225.8
    Exploration and Production                     49.3        44.2        37.2
    Other Products and Services                   (32.3)       63.8         2.3
    Corporate                                     (39.6)      (17.5)       (0.8)
--------------------------------------------------------------------------------
    CONSOLIDATED                                  418.3       695.2       590.6
--------------------------------------------------------------------------------
DEPRECIATION & DEPLETION
    Transmission and Storage                      109.3       106.2       101.8
    Distribution                                   57.4        54.5        82.2
    Exploration and Production                     33.0        36.9        36.5
    Other Products and Services                     0.2         0.4         0.3
    Corporate                                       4.8         4.2         5.0
    Adjustments and eliminations                    0.5         0.5         0.5
--------------------------------------------------------------------------------
    CONSOLIDATED                                  205.2       202.7       226.3
--------------------------------------------------------------------------------
ASSETS
    Transmission and Storage                    2,940.0     2,814.1     2,837.6
    Distribution                                3,369.4     2,831.3     2,665.1
    Exploration and Production                    851.2       774.3       590.9
    Other Products and Services                   370.6       325.9       358.4
    Corporate                                   4,638.1     4,830.2     4,298.0
    Adjustments and eliminations               (4,543.1)   (4,538.5)   (4,254.8)
--------------------------------------------------------------------------------
    CONSOLIDATED                                7,626.2     7,037.3     6,495.2
--------------------------------------------------------------------------------
CAPITAL EXPENDITURES
    Transmission and Storage                      128.9       183.4       210.0
    Distribution                                  139.6       145.5       151.9
    Exploration and Production                    128.9       166.5        75.7
    Other Products and Services                    96.0        57.3        12.1
    Corporate                                       4.9         5.4        11.0
--------------------------------------------------------------------------------
    CONSOLIDATED                                  498.3       558.1       460.7
--------------------------------------------------------------------------------
</TABLE>


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

18. QUARTERLY FINANCIAL DATA (UNAUDITED)

Quarterly financial data does not always reveal the trend of Columbia's business
operations due to nonrecurring transactions and seasonal weather patterns which
affect earnings and related components of net revenues and operating income.

<TABLE>
<CAPTION>
                                                    First        Second         Third     Fourth
($ in millions, except per share data)             Quarter       Quarter       Quarter    Quarter
===================================================================================================
<S>                                                <C>           <C>           <C>        <C>
2000
 Net Revenues                                       619.4         386.6         354.0      576.5
 Operating Income (Loss)                            273.7          79.5          73.6       (8.5)
 Income from Continuing Operations                  143.4          82.9          19.5       48.8
 Gain (Loss) from Discontinued Operations -
   net of taxes                                       6.3         (35.2)        (83.3)     (48.7)
 Net Income (Loss)                                  149.7          47.7(a)      (63.8)       0.1(b)
===================================================================================================
1999
 Net Revenues                                       627.4         370.7         333.3      576.6
 Operating Income                                   283.4          74.7          57.9      279.2
 Income from Continuing Operations                  160.9          35.3          20.5      171.1
 (Loss) from Discontinued Operations -
   net of taxes                                     (10.5)         (9.2)        (43.2)     (75.7)
 Net Income (Loss)                                  150.4(c)       26.1(d)      (22.7)      95.4(e)
===================================================================================================
</TABLE>

(a)  Includes $59 million gain on the sale of Cove Point LNG.
(b)  Includes $86.4 million gain on the sale of Columbia Electric's four power
     generation plants and the remainder of Columbia Electric.
(c)  Includes $20.6 million gain from the producer contract settlement stemming
     from Columbia's bankruptcy proceedings concluded in 1995.
(d)  Includes $6.9 million benefit from the reduction in tax expense for state
     net operating loss carryforwards.
(e)  Includes $49 million gain recorded in connection with the termination of a
     cogeneration power purchase contract and $7.8 million gain on the sale of
     Columbia's interest in the Trailblazer pipeline system.

19. EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)

During 1999, Columbia Resources' acquisition strategy involved six transactions
totaling approximately $61 million, added reserves of 65 Bcfe and expanded the
gathering infrastructure by more than 450 miles of pipeline. Also in 1999,
Columbia Resources discovered reserves in West Virginia in the Trenton-Black
river formation at depths exceeding 10,000 feet.

On August 7, 1997, Columbia Resources acquired Alamco, Inc. (Alamco), a gas and
oil production company operating in the Appalachian Basin. The information
contained in the following tables includes amounts attributable to the
operations and reserves of Alamco from August 7, 1997.


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

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

<TABLE>
<CAPTION>
RESERVE QUANTITY INFORMATION                       United States                  Canada
-----------------------------------------------------------------------------------------------
                                                           Oil & Other              Oil & Other
                                                  Gas        Liquids        Gas        Liquids
Proved Reserves                                  (Bcf)     (000 Bbls)      (Bcf)     (000 Bbls)
===============================================================================================
<S>                                           <C>          <C>             <C>      <C>
Reserves as of December 31, 1997                800.5        1,700            --           --
   Revisions of previous estimate               (23.1)         178            --           --
   Extensions, discoveries
    and other additions                          60.7           94            --           --
   Production                                   (39.0)        (201)         (0.1)       (13)
   Purchase of reserves-in-place                   --           --           1.1         77
   Sale of reserves-in-place                     (9.6)          --            --           --
-----------------------------------------------------------------------------------------------
Reserves as of December 31, 1998                789.5        1,771           1.0         64
   Revisions of previous estimate                34.4           99            --          9
   Extensions, discoveries
    and other additions                         116.8           38           0.3         40
   Production                                   (45.6)        (175)         (0.2)       (10)
   Purchase of reserves-in-place                 58.2          539            --         --
   Sale of reserves-in-place                     (2.8)          --            --         --
-----------------------------------------------------------------------------------------------
Reserves as of December 31, 1999                950.5        2,272           1.1        103
   Revisions of previous estimate                82.2         (764)           --         (9)
   Extensions, discoveries
    and other additions                         120.1           30            --         95
   Production                                   (52.3)        (204)         (0.1)       (11)
   Purchase of reserves-in-place                  2.5            4            --         --
   Sale of reserves-in-place                     (4.4)        (117)           --         --
-----------------------------------------------------------------------------------------------
RESERVES AS OF DECEMBER 31, 2000              1,098.6        1,221           1.0        178
-----------------------------------------------------------------------------------------------
Proved developed reserves as of
   December 31,
   1998                                         586.2        1,436           1.0         64
   1999                                         697.2        1,953           1.1        103
   2000                                         820.6        1,043           1.0        178
-----------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
CAPITALIZED COSTS                            United States                        Canada                       Total
----------------------------------------------------------------------------------------------------------------------------------
($ in millions)                          2000       1999      1998       2000      1999     1998      2000       1999       1998
==================================================================================================================================
<S>                                    <C>        <C>        <C>         <C>       <C>      <C>      <C>        <C>        <C>
CAPITALIZED COSTS AT YEAR END
    Proved properties                   838.4      762.5      673.2       9.4       1.7      1.4      847.8      764.2      674.6
    Unproved properties (a)              75.2       61.0       40.8      10.8      10.9      3.7       86.0       71.9       44.5
----------------------------------------------------------------------------------------------------------------------------------
Total capitalized costs                 913.6      823.5      714.0      20.2      12.6      5.1      933.8      836.1      719.1
Accumulated depletion                  (269.9)    (251.3)    (225.2)     (2.8)     (0.3)    (0.2)    (272.7)    (251.6)    (225.4)
----------------------------------------------------------------------------------------------------------------------------------
NET CAPITALIZED COSTS                   643.7      572.2      488.8      17.4      12.3      4.9      661.1      584.5      493.7
----------------------------------------------------------------------------------------------------------------------------------
COSTS CAPITALIZED DURING YEAR (b)
  Acquisition properties
    Proved                                3.1        1.2         --        --        --      0.7        3.1        1.2        0.7
    Unproved                             17.8        8.6        0.6       1.2       2.9      3.0       19.0       11.5        3.6
  Exploration                            34.0        6.7        2.3       6.9       1.3       --       40.9        8.0        2.3
  Development                            45.9       99.4       62.1        --       2.9      1.4       45.9      102.3       63.5
----------------------------------------------------------------------------------------------------------------------------------
COSTS CAPITALIZED                       100.8      115.9       65.0       8.1       7.1      5.1      108.9      123.0       70.1
----------------------------------------------------------------------------------------------------------------------------------
</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(E) of Notes to Consolidated Financial Statements of
     $3.4 million in 2000, 3.5 million in 1999 and $3.3 million in 1998.


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

<TABLE>
<CAPTION>
OTHER EXPLORATION AND PRODUCTION DATA                    United States                 Canada
---------------------------------------------------------------------------------------------------------
                                                  2000      1999      1998       2000      1999     1998
=========================================================================================================
<S>                                              <C>       <C>       <C>       <C>       <C>       <C>
Average sales price per Mcf of gas ($)(a)         2.99      2.66      2.91      3.79      2.25      2.61
Average sales price per barrel
   of oil and other liquids ($)                  25.01     14.69     12.53     30.86     19.43     16.42
Production (lifting) cost per
   dollar of gross revenue ($)                    0.18      0.19      0.21      0.36      0.18      0.32
Depletion rate per dollar
   of gross revenue ($)                           0.17      0.26      0.29      3.26      0.24      0.27
---------------------------------------------------------------------------------------------------------
</TABLE>

(a)  Includes the effect of hedging activities.


HISTORICAL RESULTS OF OPERATIONS

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------
                                   United States                Canada                    Total
---------------------------------------------------------------------------------------------------------
($ in millions)             2000      1999     1998    2000     1999    1998     2000      1999     1998
=========================================================================================================
<S>                        <C>       <C>       <C>     <C>      <C>      <C>     <C>       <C>      <C>
Gross revenues
    Unaffiliated           159.6     122.4     53.7     0.8      0.5     0.6     160.4     122.9    54.3
    Affiliated               2.0       1.4     62.3      --       --      --       2.0       1.4    62.3
Production costs            28.4      23.7     24.2     0.3      0.1     0.2      28.7      23.8    24.4
Depletion                   29.3      32.8     33.5     2.5      0.1     0.2      31.8      32.9    33.7
Income tax expense          39.8      25.0     20.7    (0.9)     0.1     0.1      38.9      25.1    20.8
---------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS       64.1      42.3     37.6    (1.1)     0.2     0.1      63.0      42.5    37.7
---------------------------------------------------------------------------------------------------------
</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>
------------------------------------------------------------------------------------------------------------------------------
                                           United States                   Canada                         Total
------------------------------------------------------------------------------------------------------------------------------
($ in millions)                  2000         1999        1998      2000    1999    1998       2000         1999        1998
==============================================================================================================================
<S>                            <C>          <C>         <C>         <C>     <C>     <C>      <C>          <C>         <C>
Future cash inflows            11,475.5     2,805.4     2,094.4     14.5     5.5     3.4     11,490.0     2,810.9     2,097.8
Future production costs        (1,608.9)     (739.8)     (585.5)    (2.9)   (2.1)   (1.5)    (1,611.8)     (741.9)     (587.0)
Future development costs         (302.7)     (258.3)     (200.4)    (0.2)   (0.1)   (0.1)      (302.9)     (258.4)     (200.5)
Future income tax expense      (3,842.3)     (697.5)     (487.8)    (2.2)   (0.9)   (0.7)    (3,844.5)     (698.4)     (488.5)
------------------------------------------------------------------------------------------------------------------------------
Future net cash flows           5,721.6     1,109.8       820.7      9.2     2.4     1.1      5,730.8     1,112.2       821.8
Less: 10% discount              3,416.0       600.6       440.1      3.9     0.9     0.3      3,419.9       601.5       440.4
------------------------------------------------------------------------------------------------------------------------------
STANDARDIZED MEASURE OF
  DISCOUNTED FUTURE
  NET CASH FLOW                2,305.6       509.2       380.6      5.3     1.5     0.8      2,310.9       510.7       381.4
------------------------------------------------------------------------------------------------------------------------------
</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.

                                       55
<PAGE>   56
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>
                                           United States                      Canada                           Total
----------------------------------------------------------------------------------------------------------------------------------
($ in millions)                   2000         1999       1998       2000      1999       1998      2000        1999         1998
==================================================================================================================================
<S>                            <C>           <C>         <C>         <C>       <C>       <C>    <C>            <C>         <C>
Beginning of year                 509.2       380.6       460.7       1.5       0.8        --       510.7       381.4       460.7
----------------------------------------------------------------------------------------------------------------------------------
Gas and oil sales,
   net of production costs       (133.2)     (100.1)      (91.9)     (0.5)     (0.4)     (0.4)     (133.7)     (100.5)      (92.3)

Net changes in prices
   and production costs         2,828.2        74.7      (108.5)      4.6       0.6        --     2,832.8        75.3      (108.5)

Change in future
   development costs              (19.0)      (35.8)      (10.0)     (0.2)       --        --       (19.2)      (35.8)      (10.0)

Extensions, discoveries
   and other additions,
   net of related costs           448.2       107.5        77.5       1.2       0.6        --       449.4       108.1        77.5

Revisions of previous
   estimates, net of
   related costs                  314.9        33.7       (18.0)     (0.1)      0.1        --       314.8        33.8       (18.0)

Sales of reserves-in-place         (5.9)       (2.9)      (12.0)       --        --        --        (5.9)       (2.9)      (12.0)

Purchases of reserves-in-
  place                            16.3        54.6          --        --        --       1.7        16.3        54.6         1.7

Accretion of discount              82.0        60.0        70.1       0.2       0.1        --        82.2        60.1        70.1

Net change in income
  taxes                        (1,233.5)      (91.3)       21.1      (0.7)     (0.2)     (0.5)   (1,234.2)      (91.5)       20.6

Timing of production
   and other changes             (501.6)       28.2        (8.4)     (0.7)     (0.1)       --      (502.3)       28.1        (8.4)
----------------------------------------------------------------------------------------------------------------------------------
END OF YEAR                     2,305.6       509.2       380.6       5.3       1.5       0.8     2,310.9       510.7       381.4
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       56
<PAGE>   57
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     Deductions      Balance
===============================================================================================================
<S>                                           <C>            <C>           <C>          <C>             <C>
 Allowance for doubtful accounts(a)

     2000                                        11.3         19.7          28.3           43.5           15.8

     1999                                        13.4         17.4          30.6           50.1           11.3

     1998                                        16.3         18.6          26.8           48.3           13.4

  Restructuring Activities(b)

     2000                                           -         66.9             -            5.2           61.7

  Environmental

     2000                                       123.6          0.5             -           17.7          106.4

     1999                                       140.9          0.2             -           17.5          123.6

     1998                                       129.1         29.2             -           17.4          140.9
===============================================================================================================
</TABLE>

(a)  Other Accounts primarily reflect reclassifications to a regulatory asset of
     the uncollectible accounts related to the Percent of Income Plan (PIP) of
     Columbia Gas of Ohio, Inc. and Deductions principally reflect amounts
     charged off as uncollectible less amounts recovered.

(b)  Deductions primarily reflect payments of severance and related termination
     benefits.

                                       57
<PAGE>   58
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

Omitted pursuant to General Instruction I. (2) (c).

ITEM 11. EXECUTIVE COMPENSATION

Omitted pursuant to General Instruction I. (2) (c).

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Omitted pursuant to General Instruction I. (2) (c).

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Omitted pursuant to General Instruction I. (2) (c).


                                     PART IV

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

Exhibits

Reference is made to pages 61 through 63 for the list of exhibits filed as 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 this Annual Report on Form 10-K are included in Item 8.

Reports on Form 8-K

<TABLE>
<CAPTION>
                     Financial
           Item      Statements
         Reported     Included           Date of Event            Date Filed
         --------     --------           -------------            ----------
<S>                  <C>               <C>                     <C>
             5          No             October 2, 2000         October 2, 2000
             5          No             October 11, 2000        October 12, 2000
             5          No             October 16, 2000        October 16, 2000
             5          No             November 1, 2000        November 1, 2000
</TABLE>


                                       58
<PAGE>   59
                                   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 28, 2001                     By: /s/ Michael W. O'Donnell
                                                ------------------------------
                                                     Michael W. O'Donnell
                                                   President and Treasurer
                                                (Principal Executive Officer)


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

<TABLE>
<S>                 <C>                                <C>               <C>
March 28, 2001       /s/ Michael W. O'Donnell          March 28, 2001      /s/ Jeffrey W. Grossman
                    -----------------------------                         --------------------------
                         Michael W. O'Donnell                                 Jeffrey W. Grossman
                       President and Treasurer                                   Vice President
               (Director, Principal Executive Officer                     (Principal Accounting Officer)
                   and Principal Financial Officer)

March 28, 2001      /s/ Stephen P. Adik
                    -----------------------------
                        Stephen P. Adik
                        Director
</TABLE>


                                       59
<PAGE>   60
EXHIBIT INDEX


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

<TABLE>
<CAPTION>
                                                                                                  Reference
                                                                                                  ---------
                                                                                            File No.      Exhibit
                                                                                           --------       -------
<S>          <C>                                                                           <C>            <C>
3-A          -  Restated Certificate of Incorporation of The Columbia                       1-1098           3-A
                Gas System, Inc., as amended 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                       1-1098           3-C
                Energy Group, Inc. into The Columbia Gas System, Inc.
3-D          -  Amended and Restated By-Laws of Columbia Energy Group as of
                February 22, 2000.
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.
4-I          -  Instrument of Resignation, Appointment and Acceptance dated as              1-1098           4-I
                of  March 1, 1999, between Columbia Energy Group and Marine
                Midland Bank, as Resigning Trustee and The First National Bank
                of Chicago, as Successor Trustee.
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.
</TABLE>

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


                                       60
<PAGE>   61
EXHIBIT INDEX (continued)

<TABLE>
<CAPTION>
                                                                                                   Reference
                                                                                                   ---------
                                                                                            File No.        Exhibit
                                                                                            --------        -------
<S>          <C>                                                                            <C>             <C>
10-AF        -  Amended and Restated Indenture of Mortgage and Deed of Trust                1-1098           10-AF
                by Columbia Gas Transmission Corporation to Wilmington Trust
                Company, dated as of November 28, 1995.
10-BB(a)     -  Annual Incentive Compensation Plan of The Columbia Gas                      1-1098           10-BB
                System, Inc., as amended, dated as of 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-BG        -  Third amendment to employment agreement by and between the
                Columbia Energy Group and Oliver G. Richard III, effective July
                21, 2000.
10-BH        -  Second amendment to employment agreement by and between the
                Columbia Energy Group and Peter M. Schwolsky, effective July
                21, 2000.
10-BI        -  Second amendment to employment agreement by and between the
                Columbia Energy Group and Catherine Good Abbott, effective July
                21, 2000.
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-BZ*       -  Natural Gas Advance Sale Contract dated August 24,
                2000, between Columbia Natural Resources, Inc.
                and Mahania II Limited.
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,                    1-1098           10-CD
                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,                    1-1098           10-CE
                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                   1-1098           10-CF
                Project partners (Columbia Transmission, West Coast Energy, MCN
                Investment Corp. and TransCanada Pipelines Limited) dated
                December 1, 1997.
10-CG        -  Agreement of Limited Partnership of Millennium Pipeline                     1-1098           10-CG
                Company, L.P. dated May 31, 1998.
</TABLE>

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

           *   Filed herewith.
                                       61
<PAGE>   62
EXHIBIT INDEX (continued)

<TABLE>
<CAPTION>
                                                                                                 Reference
                                                                                                 ---------
                                                                                           File No.         Exhibit
                                                                                           --------         -------
<S>          <C>                                                                           <C>              <C>
10-CH        -  Contribution Agreement Between Columbia Gas Transmission                    1-1098           10-CH
                Corporation and Millennium Pipeline Company, L.P. dated July 31, 1998.
10-CI        -  Regulations of Millennium Pipeline Management Company, L.L.C.               1-1098           10-CI
                dated May 31, 1998.
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-CK        -  Amended and Restated 364-Day Credit Agreement among Columbia                1-1098           10-CK
                Energy Group and certain banks party thereto and Citibank, N. A.
                as Administrative and Syndication Agent dated as of March 10, 1999.         1-1098           10-CM
10-CM        -  Plan of Reorganization for Columbia Gas Transmission
                Corporation as filed with the United States Bankruptcy
                Court for the District of Delaware on January 18, 1994.
10-CQ        -  $50,000,000 Amended and Restated Credit Agreement dated                     1-1098           10-CQ
                October 11, 2000, among Columbia Energy Group and certain
                banks party thereto and Citibank, N.A. as Administrative and
                Syndication Agent.
10-CR        -  $850,000,000 Amended and Restated Credit Agreement dated                    1-1098           10-CR
                October 11, 2000, among Columbia Energy Group and certain
                banks party thereto and Citibank, N.A. as Administrative and
                Syndication Agent.
12*          -  Statements of Ratio of Earnings to Fixed Charges
                and Preferred Stock Dividends.
23-A*        -  Written consent, dated March 12, 2001, to the filing and
                use of information contained in such letter report, in Reports
                and Registration Statements filed during 2000, of Ryder Scott
                Company Petroleum Engineers, independent petroleum and natural
                gas consultants.
23-B*        -  Written consent, dated January 22, 2001, to the filing and
                use of information contained in such letter report, in Reports
                and Registration Statements filed during 2000, of Sproule
                Associates Limited, independent petroleum and natural gas
                consultants.
</TABLE>

  * Filed herewith.


                                       62