<PAGE>

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                       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

                         Commission File Number 1-3196

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

                        CONSOLIDATED NATURAL GAS COMPANY
                             A DELAWARE CORPORATION
                 120 TREDEGAR STREET, RICHMOND, VIRGINIA 23219
                            TELEPHONE (804) 819-2000

                 IRS EMPLOYER IDENTIFICATION NUMBER 54-1966737

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

<TABLE>
<S>                                      <C>
Notes:                                   Registered:
  7 1/4% Notes Due October 1, 2004                           --
Debentures:
  6.0% Debentures Due October 15, 2010   New York Stock Exchange
  6.8% Debentures Due December 15, 2027  New York Stock Exchange
  6 5/8% Debentures Due December 1, 2008 New York Stock Exchange
  6 7/8% Debentures Due October 15, 2026 New York Stock Exchange
  7 3/8% Debentures Due April 1, 2005    New York Stock Exchange
  6 5/8% Debentures Due December 1, 2013 New York Stock Exchange
  5 3/4% Debentures Due August 1, 2003   New York Stock Exchange
  8 3/4% Debentures Due October 1, 2019  New York Stock Exchange
</TABLE>

          Securities registered pursuant to section 12(g) of the Act:

                                      None

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

   Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [_]
   Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
   The aggregate market value of the voting stock held by non-affiliates of the
registrant as of March 2, 2001, was zero.
   As of March 2, 2001 there were issued and outstanding 100 shares of the
registrant's common stock, without par value, all of which were held,
beneficially and of record, by Dominion Resources, 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.

--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

<TABLE>
<CAPTION>
Item
Number                                                                    Page
------                                                                    ----
<S>                                                                       <C>
                                 PART I
1. Business
  The Company............................................................   3
  Competition............................................................   4
    Distribution.........................................................   4
    Transmission.........................................................   5
    Exploration and Production...........................................   5
  Regulation.............................................................   6
  Environmental Matters..................................................   6
  Gas Supply.............................................................   7
    Gas Purchased........................................................   7
    Gas Storage..........................................................   7
    Gas and Oil Producing Activities.....................................   7
  Gas Utility Customers..................................................   8
  Gas Sales, Supply, Transportation and Storage Statistics ..............  10
  Rates..................................................................  11
2. Properties............................................................  11
  Gas and Oil Producing Activities.......................................  12
    Company-Owned Reserves...............................................  12
    Quantities of Gas and Oil Produced...................................  12
    Productive Wells.....................................................  13
    Acreage..............................................................  13
    Net Wells Drilled in the Calendar Year...............................  14
3. Legal Proceedings.....................................................  14
4. Submission of Matters to a Vote of Security Holders...................  15

                                 PART II

5. Market for the Registrant's Common Equity and Related Stockholder
   Matters...............................................................  16
6. Selected Financial Data...............................................  16
7. Management's Discussion and Analysis of Results of Operations.........  16
7A.Quantitative and Qualitative Disclosures about Market Risk............  29
8. Financial Statements and Supplementary Data Index.....................  30
9. Changes in and Disagreements with Accountants on Accounting and
   Financial Disclosure..................................................  74

                                PART III

10. Directors and Executive Officers of the Registrant...................  74
11. Executive Compensation...............................................  74
12. Security Ownership of Certain Beneficial Owners and Management.......  74
13. Certain Relationships and Related Transactions.......................  74

                                 PART IV

14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.....  75
</TABLE>

                                       2
<PAGE>

                                     PART I

                                ITEM 1. BUSINESS

                                  THE COMPANY

   On January 28, 2000, Dominion Resources, Inc. (Dominion) and Consolidated
Natural Gas Company (CNG) completed the merger of CNG into a subsidiary (New
Company) of Dominion. The name of New Company was changed to Consolidated
Natural Gas Company at the time of the merger.

   To give effect to the continuity of CNG and New Company, the term "Company"
in this Annual Report on Form 10-K (Form 10-K) refers to Consolidated Natural
Gas Company both before and after the merger unless the context of a statement
requires the use of separate references to each company. Within this document,
the term "Company" shall refer to the entirety of Consolidated Natural Gas
Company and all of its subsidiaries. Shareholders of CNG received Dominion
common stock and/or cash in consideration of their CNG shares. The combination
with Dominion, based in Richmond, Virginia, creates a fully integrated electric
and natural gas utility in the Midwest, Northeast and Mid-Atlantic regions of
the United States.

   CNG, the predecessor to New Company at the time of the merger, was a
Delaware corporation organized on July 21, 1942, and a public utility holding
company registered under the Public Utility Holding Company Act of 1935 (1935
Act). New Company is a Delaware corporation incorporated on September 14, 1999
and is a public utility holding company registered under the 1935 Act. Dominion
is also a public utility holding company registered under the 1935 Act. The
Company is engaged solely in the business of owning and holding all of the
outstanding equity securities of directly owned subsidiary companies.

   The Company, through its subsidiaries, operates in all phases of the natural
gas business, explores for and produces oil, and provides a variety of retail
energy marketing services. At December 31, 2000, the Company had approximately
4,800 employees.

   We currently manage our operations in a manner that requires disclosure of
four business segments: Distribution, Transmission, Exploration and Production
and Other.

   Our Distribution segment includes three gas distribution subsidiaries: The
East Ohio Gas Company (Dominion East Ohio), The Peoples Natural Gas Company
(Dominion Peoples) and Hope Gas, Inc. (Dominion Hope). These subsidiaries serve
various cities located in Ohio, including Cleveland; Pennsylvania, including
Pittsburgh; and West Virginia. At December 31, 2000, the Company served at
retail approximately 1.7 million residential, commercial and industrial gas
sales and transportation customers in Ohio, Pennsylvania and West Virginia.

   In October 2000, the Company completed the sale of its fourth gas
distribution subsidiary, Virginia Natural Gas, Inc. (VNG), to AGL Resources
Inc. in accordance with the conditions set forth by the Virginia State
Corporation Commission (Virginia Commission) and the Federal Trade Commission
in connection with their approval of the acquisition of CNG by Dominion.

   Our Transmission segment includes certain operations of Dominion
Transmission, Inc., formerly CNG Transmission Corporation (Dominion
Transmission), the operations of Dominion Field Services, Inc., formerly CNG
Field Services Company (Dominion Field Services) and the gas by-products
operations of CNG Power Company (CNG Power). Dominion Transmission is an
interstate pipeline company regulated by the Federal Energy Regulatory
Commission (FERC) which provides gas transportation, storage and related
services to affiliates and to utilities and end users in the Midwest, the Mid-
Atlantic states and the Northeast. Dominion Transmission also holds a 16%
partnership interest in the Iroquois Gas Transmission System, L.P., a limited
partnership that owns and operates an interstate natural gas pipeline that
transports Canadian gas to utility and power generation customers in New York
and New England. Dominion Field Services is engaged in activities related to
Appalachian area natural gas supply. CNG Power exited the gas by-products
business during 2000.

                                       3
<PAGE>

   The regional interstate pipeline system of Dominion Transmission, located in
Ohio, Pennsylvania, West Virginia and New York, serves as a link between the
country's major gas pipelines and large markets on the East Coast. With its
large underground gas storage capacity, Dominion Transmission provides gas
storage service to affiliates, end users and others, including utilities who
primarily serve customers in the Northeast. The Appalachian area gas supply
activities of Dominion Field Services consist generally of aggregating gas
supply from local producers for resale to affiliates, marketers and end users.
In May 2000, Dominion transferred its Appalachian gas marketing operation to
Dominion Field Services as part of its overall restructuring program.

   Our Exploration and Production segment includes Dominion Exploration &
Production, Inc., formerly CNG Producing Company (Dominion E&P), and the gas
and oil production activities of Dominion Transmission. Dominion E&P is a gas
and oil exploration and production subsidiary whose activities are conducted
primarily in the Gulf of Mexico, the southern and western United States, the
Appalachian region and Canada. Dominion E&P's Canadian properties were
transferred by sale to another subsidiary of Dominion, effective January 1,
2001.

   Our Other segment includes the results of Dominion Retail, Inc., formerly
CNG Retail Services Corporation (Dominion Retail), Dominion Products and
Services, Inc., formerly CNG Products and Services, CNG International
Corporation (CNG International) and other minor subsidiaries of the Company.
Dominion Retail, a nonregulated company, markets natural gas, electricity and
related products and services to residential, commercial and small industrial
customers. Dominion Products and Services provides energy-related services to
customers of the Company's local distribution subsidiaries and others. CNG
International is engaged in energy-related activities outside of the United
States, primarily through equity investments in Australia. The Company has
decided to focus on its core business segments above and is committed to a plan
of disposal of its international assets. Accordingly, in October 2000, the
Company completed the sale of its Argentine assets to Sempra Energy
International for $145 million.

                                  COMPETITION

Distribution

   Competition in the markets served by the distribution subsidiaries continues
to increase. As the gas industry has restructured and government regulations
have changed, a marketplace has evolved with new and traditional competitors--
the usual oil and electric companies, other gas companies, producers seeking to
gain direct access to the Company's customers, and gas brokers and dealers
seeking to replace supplies with spot market gas. Natural gas faces price
competition with other energy forms, and certain distribution companies'
industrial customers have the ability to switch to fuel oil or coal if desired.
In addition, competition is increasing among local distribution companies to
provide gas sales and transportation services to commercial and residential
customers. Currently, local distribution companies operate in what are
essentially dual markets--a traditional utility market, where a utility has an
obligation to provide service and offers a "bundled" package of services to all
customers; and a "contract" market, where obligations are defined by contract
terms. In the latter market, large customers can elect individually or in
various combinations whatever gas supplies, storage and/or transportation
services they require. The Company has responded to this competitive
environment by offering a variety of firm and interruptible services, including
gas transportation, storage, supply pooling and balancing, and brokering, to
industrial and commercial customers.

   Dominion has taken steps to offer choices to its customers in Pennsylvania.
As early as 1984, large industrial customers in Pennsylvania began to buy
natural gas supplies from third parties, rather than directly from local
utilities; the local distributors transported these third-party gas supplies to
the industrial facilities. Since that time, nearly all Pennsylvania industrial
and large commercial customers have changed from utility sales customers to
transportation services customers, buying the natural gas commodity from
unregulated suppliers and transporting it on our gas delivery network. In 1997,
Dominion Peoples voluntarily launched an

                                       4
<PAGE>

Energy Choice program for all of its retail consumers in Pennsylvania --
whether industrial, commercial, or residential. Subsequently, in 1999,
Pennsylvania enacted legislation to mandate supplier choice for residential and
small commercial customers. At December 31, 2000, approximately 106,000
customers had opted for Energy Choice in the Company's Pennsylvania service
area.

   Large industrial customers in Ohio began to source their own natural gas
supplies in the mid-1980's, as interstate pipeline transportation services
became more widely available. However, to date Ohio has not enacted legislation
to require supplier choice for residential and commercial natural gas
consumers. Dominion East Ohio has made significant progress in offering Energy
Choice to customers on its own initiative, in cooperation with The Public
Utilities Commission of Ohio. In 1997, Dominion East Ohio launched a pilot
program designed to make gas transportation service available to residential
and small commercial customers, and to the suppliers that market gas to these
customer classes. In 2000, the Energy Choice program was expanded to all 1.2
million customers in Dominion's Ohio service area. At December 31, 2000,
approximately 175,000 of Dominion's Ohio customers were participating in this
open access program.

   At this time, West Virginia has not enacted legislation to require customer
choice in its retail natural gas markets. In this smaller, more rural market
area, Dominion has not voluntarily initiated an energy choice program. However,
the West Virginia Public Service Commission recently issued regulations to
govern pooling services; these services are one of the tools that natural gas
suppliers may utilize to provide retail customer choice in the future.

Transmission

   Dominion Transmission has taken advantage of selected market expansion
opportunities, concentrating its efforts primarily in the Northeast and along
the East Coast. Dominion Transmission's large underground storage capacity and
the location of its gridlike pipeline system as a link between the country's
major gas pipelines and large markets on the East Coast have been key factors
in the success of these expansion efforts. The Company's pipelines are part of
an interconnected gas transmission system which will continue to enable retail
end users to take advantage of the accessibility of supplies nationwide as gas
utilities unbundle services at the retail level.

   Dominion Transmission competes with domestic as well as Canadian pipeline
companies and gas marketers seeking to provide or arrange transportation,
storage and other services for customers. Also, certain end users have the
ability to switch to fuel oil or coal if desired. Although competition is based
primarily on price, the array of services that can be provided to customers is
also an important factor. The combination of capacity rights held on certain
longline pipelines, a large storage capability and the availability of numerous
receipt and delivery points along its own pipeline system enables Dominion
Transmission to tailor its services to meet the individual needs of customers.

Exploration and Production

   Exploration and production operations are conducted by the Company in
several major gas and oil producing basins in the United States, both onshore
and offshore. In this highly competitive business, the Company competes with a
large number of entities ranging in size from large international oil companies
with extensive financial resources to small, cash flow driven independent
producers.

   Dominion E&P faces significant competition in the bidding for federal
offshore leases and in obtaining leases and drilling rights for onshore
properties. Since Dominion E&P is the operator of a number of properties, it
also faces competition in securing drilling equipment and supplies for
exploration and development.

   From the production perspective, the marketing of gas and oil is highly
competitive with price being the most significant factor. Gas producers
throughout the industry, including Dominion E&P, face a diverse and active
market with purchasers seeking to balance the advantage of flexible spot market
supplies with the

                                       5
<PAGE>

security of longer-term contracts. The growth of gas and energy marketing
firms has added to the competition for Dominion E&P.

   See also Gas and Electric Industry Developments under MANAGEMENT'S
DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS.

                                  REGULATION

   Many aspects of the Company's business are presently subject to regulation
by the Securities and Exchange Commission (SEC), FERC, the Environmental
Protection Agency (EPA), Department of Energy (DOE), and other federal, state
and local authorities.

   The Company is also subject to the Natural Gas Act of 1938, as amended.
Interstate transportation and storage activities are regulated under such Act
and are conducted in accordance with tariffs and service agreements on file
with FERC. The distribution subsidiaries are subject to regulation by the
respective utility commissions in the states within which they operate.
Dominion Retail, a public utility as defined by Section 201 of the Federal
Power Act, is subject to limited FERC regulation. Additionally, Dominion
Retail is classified as a public utility in Pennsylvania for the limited
purpose of its participation in the Pennsylvania retail access programs.

   Certain subsidiaries are also subject to various provisions of the five
statutes which are referred to as the National Energy Act of 1978.

   The Natural Gas Pipeline Safety Act of 1968 (which, among other things,
authorizes the establishment and enforcement of federal pipeline safety
standards) subjects the interstate pipeline of Dominion Transmission to the
safety jurisdiction of the Department of Transportation. Intrastate facilities
remain within the safety jurisdiction of the state regulatory agencies,
presuming compliance by such agencies with certain prerequisites contained in
such Act.

Environmental Matters

   The Company is subject to various federal, state and local laws and
regulations relating to the protection of the environment. These laws and
regulations govern both current and future operations and potentially extend
to plant sites formerly owned or operated by the subsidiaries, or their
predecessors.

   Dominion Transmission and certain of the distribution subsidiaries are
subject to the Federal Clean Air Act (Clean Air Act) and the Federal Clean Air
Act Amendments of 1990 (1990 amendments) which added significantly to the
existing Clean Air Act requirements. As a result of the 1990 amendments, these
subsidiaries were required to acquire Title V permits for major facilities.
Progress is on schedule for these permits, with no major expenditures
anticipated. The 1990 amendments will also require installation of Maximum
Available Control Technology (MACT) to control the emissions of certain
hazardous air pollutants from compressor engines. The Company cannot estimate
what its expenditures for MACT-related controls will be. However, the mandated
controls will not affect a large number of its compressor engines and the
related costs are not expected to be material.

   The exact nature of environmental issues that the Company may encounter in
the future cannot be predicted. At present, no estimate of any such additional
liability, or range of liability amounts, can be made. However, the amount of
any such liabilities could be material.

   For additional discussion on environmental matters, see Note 19 to the
Consolidated Financial Statements.

                                       6
<PAGE>

                                   GAS SUPPLY

   The Company's gas supply is obtained from various sources including:
purchases from major and independent producers in the Southwest and Midwest
regions; purchases from local producers in the Appalachian area; purchases from
gas marketers; production from Company-owned wells in the Appalachian area, the
Southwest, Midwest and offshore; and withdrawals from the Company's and third-
party underground storage fields.

Gas Purchased

   The Company has continued to purchase volumes from the array of accessible
producing basins using its firm capacity resources. These purchased supplies
include Appalachian resources in Ohio, Pennsylvania and West Virginia, and
production from the Gulf Coast, Mid-Continent and offshore areas. Gas purchase
contract terms have continued to undergo transformation initiated with the
removal of Dominion Transmission and other gas pipelines from the merchant
function. Much of the supply is purchased under seasonal or spot purchase
agreements. While the average term of the Company's gas purchase agreements has
declined, the reliability of supply has been adequate. The availability of
supplies and heightened competition have forged a viable market which has
proven capable of satisfying the firm delivery requirement for supplies to the
Company's markets in a highly reliable manner.

   Purchased gas volumes were 422 billion cubic feet (Bcf) in 2001 representing
about 70% of the Company's 2000 gas supply of 601 Bcf. Spot market and short-
term purchases were 398 Bcf, or about 66% of the total 2000 supply.

Gas Storage

   The Company's underground storage facilities play an important part in
balancing gas supply with sales demand and are essential to servicing the
Company's large volume of space-heating business. In addition, storage capacity
is an important element in the effective management of both gas supply and
pipeline transport capacity. The Company operates 26 underground gas storage
fields located in Ohio, Pennsylvania, West Virginia and New York. The Company
owns 20 of these storage fields and has joint ownership with other companies in
six of the fields. The total designed capacity of the storage fields, including
native gas, is approximately 959 Bcf. The Company's share of the total capacity
is about 717 Bcf. About one-half of the total capacity is base gas which
remains in the reservoirs at all times to provide the primary pressure which
enables the balance of the gas to be withdrawn as needed.

   Dominion Transmission operates 756 Bcf of the total designed storage
capacity and owns 514 Bcf of the Company's capacity. Dominion Transmission
utilizes a large portion of its turnable capacity to provide approximately 275
Bcf of gas storage service for others. This service is provided principally to
affiliates, end users, and other customers who primarily serve consumers in the
Northeast.

   Two of the distribution subsidiaries, Dominion East Ohio and Dominion
Peoples, own and operate the remaining 203 Bcf of storage capacity. In addition
to owning their own storage, these companies, as well as several of the other
subsidiaries, have access to a portion of the storage capacity operated by
Dominion Transmission. The distribution subsidiaries also have capacity
available in storage fields owned by others. The Company controls other acreage
in the Appalachian area suitable for the development of additional storage
facilities which would enable further expansion of capacity to meet possible
future storage needs.

Gas and Oil Producing Activities

   Following the merger with Dominion, the Company changed its method of
presenting gas and oil financial and statistical information from a "net before
royalty" basis to a "net revenue" basis to conform to

                                       7
<PAGE>

Dominion's presentation. As a result, amounts previously reported for revenue,
royalty expense, and gas and oil reserves and production have been restated.
The change to the "net revenue" basis also conforms the Company's presentation
to that widely used by the industry.

   The Company's total gas production in 2000 was 173 Bcf, up from 153 Bcf in
1999. Oil production was 7.2 million barrels, down from 8.5 million barrels in
1999. The Company's gas wellhead prices in 2000 averaged $3.08 a thousand cubic
feet (Mcf), up from $2.26 in 1999. The Company's average gas wellhead prices
are generally higher and less volatile than industry spot prices since its
average price reflects a mix of longer-term contracts and the impact of price
risk management activities. The average oil wellhead price in 2000 increased to
$18.60 a barrel, compared with $12.67 in 1999, consistent with the general
increase in world oil prices. The Company's average oil wellhead prices also
reflect the impact of price risk management activities.

   The following table sets forth 2000 drilling activity by region:

<TABLE>
<CAPTION>
                                                          Wells Drilled
                                                     -------------------------
                                                     Exploratory  Development
                                                     ------------ ------------
                                                     Gross  Net   Gross  Net
                                                     ------ ----- ------ -----
   <S>                                               <C>    <C>   <C>    <C>
   Onshore (Southwest and West).....................     12     5     46    32
   Gulf of Mexico...................................     11     5     15     7
   Appalachian Region...............................      3     1     89    88
   Canada...........................................                  45    10
                                                      ----- -----  ----- -----
     Total..........................................     26    11    195   137
                                                      ===== =====  ===== =====
</TABLE>

   Of the total 221 gross wells drilled in 2000, 197 were successful, an 89%
success rate. Of the 26 gross exploratory wells drilled, 6 were successful.

   Total Company-owned proved gas reserves at year-end were 1,224 Bcf, up from
1,205 Bcf at the end of 1999. Proved oil reserves were 57.3 million barrels,
compared with 49.3 million barrels in 1999. The Company added 302 Bcf of gas
equivalent from additions, revisions, and purchases of gas and oil reserves in
2000.

   At year-end 2000, the Company held 2.1 million net acres of exploration and
production properties, approximately the same as year-end 1999. The Company's
lease holdings include about 1.4 million net acres in the Appalachian area,
444,000 in the offshore Gulf of Mexico, and 280,600 in the inland areas of the
Southwest, Gulf Coast and West. Effective January 1, 2001, the Company
transferred its 21% interest in heavy oil producing properties in Alberta,
Canada, to another subsidiary of Dominion. Proved reserves associated with the
Canadian properties approximated 1 Bcf of gas and 6.6 million barrels of oil at
December 31, 2000. On an energy-equivalent basis, these reserves represent less
than 3% of the Company's total proved reserves at that date.

   The Company will continue to review its property inventory during 2001, and
sales of selected properties are possible depending on economic conditions.

                             GAS UTILITY CUSTOMERS

   The following table provides information regarding the number of customers
served at December 31, 1996 through 2000. The information for the years 1996
through 1999 includes customers of VNG, a subsidiary that was sold in October
2000. During this period, VNG averaged 202,000 residential customers, 17,600
commercial customers and 90 industrial customers.

                                       8
<PAGE>

   The decline in the number of residential customers since 1996 reflects the
shift of residential sales customers to other suppliers under customer choice
programs.

<TABLE>
<CAPTION>
                                  Customers
                                  ---------
      Total(a)  Residential Commercial Industrial Wholesale Nonregulated
      --------  ----------- ---------- ---------- --------- ------------
<S>   <C>       <C>         <C>        <C>        <C>       <C>
2000  1,701,833  1,295,196   108,262       722        12      297,641
1999  1,880,730  1,616,175   122,655       866        11      141,023
1998  1,878,008  1,605,426   121,395       919        11      150,257
1997  1,864,853  1,655,587   124,141     1,813        39       83,273
1996  1,841,227  1,713,504   125,842     1,764        37           80
</TABLE>
--------
(a) Includes residential and commercial space-heating customers as follows:
    2000-1,387,650; 1999-1,710,431; 1998-1,695,943; 1997-1,750,136; and 1996-
    1,808,062.

   The table on the next page provides five-year statistics on gas sales,
supply, transportation, and storage.

                                       9
<PAGE>

          GAS SALES, SUPPLY, TRANSPORTATION AND STORAGE STATISTICS(a)
                       (EXCLUDES AFFILIATED TRANSACTIONS)

<TABLE>
<CAPTION>
                                              Years Ended December 31,
                                         --------------------------------------
                                          2000    1999    1998    1997    1996
                                         ------  ------  ------  ------  ------
<S>                                      <C>     <C>     <C>     <C>     <C>
GAS SALES REVENUE (MILLIONS)
Regulated gas sales
  Residential........................... $1,352  $1,109  $1,090  $1,449  $1,346
  Commercial............................    346     274     268     370     362
  Industrial............................     18      13      13      23      31
  Wholesale.............................      3       1       3       9      15
Nonregulated gas sales..................    675     211     125      32     --
Gas production sales....................    399     262     265     306     286
Gas brokering...........................     70      67      50      32      52
                                         ------  ------  ------  ------  ------
    Total(b)............................ $2,863  $1,937  $1,814  $2,221  $2,092
                                         ======  ======  ======  ======  ======

AVERAGE SALES RATES PER MCF
Regulated gas sales
  Residential........................... $ 7.82  $ 6.51  $ 6.82  $ 6.97  $ 6.15
  Commercial............................   7.21    5.71    6.04    6.19    5.41
  Industrial............................   6.57    5.22    5.32    5.33    4.47
  Wholesale.............................     (c)     (c)     (c)     (c)     (c)
Nonregulated gas sales..................   3.88    2.84    2.57    3.42     --
Gas production sales....................   2.89    2.24    2.23    2.43    2.42
Gas brokering...........................   3.36    2.98    2.87    2.77    2.66
    Weighted average.................... $ 5.14  $ 4.45  $ 4.62  $ 5.30  $ 4.84
                                         ======  ======  ======  ======  ======

GAS REQUIREMENTS (BCF)
Regulated gas sales
  Residential...........................    173     171     160     208     219
  Commercial............................     48      48      44      60      67
  Industrial............................      2       2       3       4       7
  Wholesale.............................      1     --      --      --        2
Nonregulated gas sales..................    174      74      48       9     --
Gas production sales (d)................    138     117     119     126     119
Gas brokering...........................     21      23      18      12      19
                                         ------  ------  ------  ------  ------
    Total sales.........................    557     435     392     419     433
Used and unaccounted for................     44      62      38      29      23
                                         ------  ------  ------  ------  ------
    Total requirements..................    601     497     430     448     456
                                         ======  ======  ======  ======  ======

GAS SUPPLY (BCF)
Purchased gas...........................    422     326     295     296     353
Storage (input) withdrawal..............      6      18     --       18     (23)
Gas produced (d)
  Gulf region...........................    102     101      91      96      90
  Appalachian area......................     29      25      24      24      24
  Other areas...........................     42      27      20      14      12
                                         ------  ------  ------  ------  ------
    Total produced......................    173     153     135     134     126
                                         ------  ------  ------  ------  ------
    Total supply........................    601     497     430     448     456
                                         ======  ======  ======  ======  ======
PURCHASED GAS COSTS (MILLIONS)(e)....... $1,705  $  912  $  901  $1,114  $  963
                                         ======  ======  ======  ======  ======
AVERAGE PURCHASE RATES PER MCF(e)....... $ 4.39  $ 2.94  $ 2.95  $ 3.39  $ 3.37
                                         ======  ======  ======  ======  ======
GAS TRANSPORTATION
Revenue (Millions)...................... $  421  $  443  $  417  $  369  $  298
                                         ======  ======  ======  ======  ======
Gas transported (Bcf)...................    703     660     641     736     754
                                         ======  ======  ======  ======  ======
GAS STORED AT DECEMBER 31 (BCF).........    363     377     397     407     426
                                         ======  ======  ======  ======  ======
</TABLE>
--------
(a) Continuing operations
(b) Includes gas sales revenue attributable to VNG. VNG's total gas sales
    revenue averaged $195 million annually during the period 1996 through 1999.
(c) Demand charges and low sales volumes produce an average rate which is not
    meaningful.
(d) Restated from a "net before royalty" basis to a "net revenue" basis.
(e) Includes transportation charges.


                                       10
<PAGE>

                                     RATES

   The regulated subsidiaries continue to seek general rate increases on a
timely basis to recover increased operating costs and to ensure that rates of
return are compatible with the cost of raising capital. In addition to general
rate increases, certain distribution companies make separate filings with their
respective regulatory commissions to reflect changes in the costs of purchased
gas. The Company's regulated subsidiaries filed no new general rate cases
during 2000.

   In March 2001, Dominion Hope filed a rate case with the Public Service
Commission of West Virginia with a proposed effective date for new rates as of
January 1, 2002. No procedural schedule has been established at this time. The
proposed new rates are to provide for the increased cost of gas supplies as
well as increased operating costs.

                               ITEM 2. PROPERTIES

   The Company's total gross investment in property, plant and equipment was
$9.3 billion at December 31, 2000. The largest portion of this investment (56%)
is in facilities located in the Appalachian area. Another significant portion
(30%) is located in the Gulf of Mexico.

   Of the $9.3 billion investment, $5.0 billion is in production and gathering
systems, of which 68% is invested in the Gulf of Mexico and the Gulf coast and
20% in the Appalachian area. The Company's production subsidiary, Dominion E&P,
accounts for $4.5 billion of the $5.0 billion investment, and Dominion
Transmission and the distribution subsidiaries account for the remaining $.5
billion. In addition to the wells and acreage listed elsewhere in ITEM 2, this
investment includes 7,056 miles of gathering lines which are located almost
entirely within the Appalachian area.

   The Company's investment in its gas distribution network includes 27,060
miles of pipe, exclusive of service pipe, the cost of which represents 61% of
the $1.7 billion invested in the total function.

   The Company's storage operation consists of 26 storage fields, 342,605 acres
of operated leaseholds, 2,069 storage wells and 822 miles of pipe. The
investment in storage properties is $583 million.

   Of the $1.5 billion invested in transmission facilities, 65% represents the
cost of 6,428 miles of pipe required to move large volumes of gas throughout
the Company's operating area.

   The Company has 99 compressor stations with 492,040 installed compressor
horsepower. Some of the stations are used interchangeably for several
functions.

   The Company's investment in its natural gas system is considered suitable to
do all things necessary to bring gas to the consumer. The Company's properties
provided the capacity to meet a record system peak day sendout, including
transportation service, of 11.4 Bcf (of which 0.4 Bcf was attributable to VNG)
on February 6, 1995. The system peak day sendout in 2000 was 8.6 Bcf on January
27 (of which 0.3 Bcf was attributable to VNG).

                                       11
<PAGE>

                        GAS AND OIL PRODUCING ACTIVITIES

Company-Owned Reserves

   Estimated net quantities of proved gas and oil reserves at December 31 were
as follows:

<TABLE>
<CAPTION>
                                    2000            1999*            1998*
                              ---------------- ---------------- ----------------
                               Proved   Total   Proved   Total   Proved   Total
                              Developed Proved Developed Proved Developed Proved
                              --------- ------ --------- ------ --------- ------
<S>                           <C>       <C>    <C>       <C>    <C>       <C>
Gas reserves (Bcf):
  United States..............     973    1,223     959    1,204     894    1,109
  Canada.....................       1        1       1        1       1        1
                               ------   ------  ------   ------  ------   ------
    Total gas reserves.......     974    1,224     960    1,205     895    1,110
                               ======   ======  ======   ======  ======   ======

Oil reserves (000 Bbls):
  United States..............  21,328   50,691  32,290   42,643  30,189   41,854
  Canada.....................   6,582    6,582   6,644    6,644   4,771    4,771
                               ------   ------  ------   ------  ------   ------
    Total oil reserves.......  27,910   57,273  38,934   49,287  34,960   46,625
                               ======   ======  ======   ======  ======   ======
</TABLE>
--------
*  Restated from a "net before royalty" basis to a "net revenue" basis.

   Dominion E&P and Dominion Transmission file Form EIA-23 with the Department
of Energy. The reserves reported on Form EIA-23 at December 31, 1999, as well
as those which will be reported at December 31, 2000, are not reconcilable with
Company-owned reserves because they are calculated on an operated basis and
include working interest reserves of all parties.

Quantities of Gas and Oil Produced

   Quantities of gas and oil produced during each of the last three years
ending December 31 follow:

<TABLE>
<CAPTION>
                                                               2000  1999* 1998*
                                                               ----- ----- -----
<S>                                                            <C>   <C>   <C>
Gas production (Bcf):
  United States**.............................................   173   153   135
  Canada......................................................   --    --    --
                                                               ----- ----- -----
    Total gas production......................................   173   153   135
                                                               ===== ===== =====
Oil production (000 Bbls):
  United States............................................... 6,861 8,216 5,960
  Canada......................................................   352   329   508
                                                               ----- ----- -----
    Total oil production...................................... 7,213 8,545 6,468
                                                               ===== ===== =====
</TABLE>
--------
*  Restated from a "net before royalty" basis to a "net revenue" basis.
** Includes cost-of-service production of 2 Bcf for 1998.

   The average sales prices (including transfers to other operations as
determined under Financial Accounting Standards Board rules) per Mcf of non-
cost-of-service gas produced during the years 2000, 1999 and 1998 were $3.08,
$2.26 and $2.22, respectively. The respective average sales prices for oil were
$18.60, $12.67 and $11.75 per barrel. The average production (lifting) cost per
Mcf equivalent of gas and oil produced during the years 2000, 1999 and 1998 was
$.43, $.40 and $.37, respectively.

                                       12
<PAGE>

Productive Wells

   The number of productive gas and oil wells in which the Company's
subsidiaries have an interest at December 31, 2000, follow:

<TABLE>
<CAPTION>
                                                                     Gross  Net
                                                                     ----- -----
<S>                                                                  <C>   <C>
Gas wells:
  United States..................................................... 6,926 5,988
  Canada............................................................     2   --
                                                                     ----- -----
    Total gas wells*................................................ 6,928 5,988
                                                                     ===== =====

Oil wells:
  United States.....................................................   310   228
  Canada............................................................   596   126
                                                                     ----- -----
    Total oil wells*................................................   906   354
                                                                     ===== =====
</TABLE>
--------
*  Includes 82 gross (23 net) multiple completion gas wells and 21 gross (8
   net) multiple completion oil wells.

Acreage

   The following table sets forth the gross and net developed and undeveloped
acreage of the Company's subsidiaries at December 31, 2000:

<TABLE>
<CAPTION>
                                                                   Undeveloped
                                              Developed Acreage      Acreage
                                             ------------------- ---------------
                                               Gross      Net     Gross   Net*
                                             --------- --------- ------- -------
<S>                                          <C>       <C>       <C>     <C>
United States**............................. 2,014,017 1,556,878 822,905 519,661
Canada......................................    12,800     1,484  75,520  14,148
                                             --------- --------- ------- -------
  Total acreage............................. 2,026,817 1,558,362 898,425 533,809
                                             ========= ========= ======= =======
</TABLE>
--------
*  Approximately 18% of this acreage is located in the Appalachian area.
** Developed acreage includes 212,055 gross and net cost-of-service acres.

                                       13
<PAGE>

Net Wells Drilled in the Calendar Year

   The number of net wells completed during each of the last three years
follows:

<TABLE>
<CAPTION>
                                                                   Years Ended
                                                                   December 31,
                                                                  --------------
                                                                  2000 1999 1998
                                                                  ---- ---- ----
   <S>                                                            <C>  <C>  <C>
   Exploratory:
     United States:
       Productive................................................   2    7    9
       Dry.......................................................   9    6    7
                                                                  ---  ---  ---
         Total exploratory.......................................  11   13   16
                                                                  ---  ---  ---

   Development:
     United States:
       Productive................................................ 125   49   54
       Dry.......................................................   2    1    1
                                                                  ---  ---  ---
         Total United States..................................... 127   50   55
                                                                  ---  ---  ---

     Canada:
       Productive................................................   9    2  --
       Dry....................................................... --   --   --
                                                                  ---  ---  ---
         Total Canada............................................   9    2  --
                                                                  ---  ---  ---
         Total development....................................... 136   52   55
                                                                  ---  ---  ---
           Total wells drilled................................... 147   65   71
                                                                  ===  ===  ===
</TABLE>

   As of December 31, 2000, 25 gross (14 net) wells were in process of
drilling, including wells temporarily suspended.

                           ITEM 3. LEGAL PROCEEDINGS

   As previously reported, on April 20, 1999, the Company and the directors
party to the suit were served with a purported Class Action Complaint, Civil
Action No. 17114-NC, styled Gerold Garfinkel v. Raymond E. Galvin, Paul E.
Lego, Margaret A. McKenna, William S. Barrack, Jr., Steven A. Minter,
J. W. Connolly, George A. Davidson, Jr., Richard P. Simmons, and Consolidated
Natural Gas Company. The Complaint was filed in the Delaware Court of Chancery
on April 20, 1999. The Complaint seeks injunctive relief in the form of an
order to the individual Board members to sell the Company for the highest value
to the shareholders, an accounting of any damages resulting from any failure to
sell the Company for the highest value, a determination with respect to the
reasonableness of the break-up fee in the agreement with Dominion and other
miscellaneous relief. The Complaint also seeks an award of costs and attorneys'
fees. Several additional purported Class Action Complaints against the Company
and its directors seeking essentially the same relief have been combined with
this action. The Company has moved to dismiss. On February 15, 2000, the
plaintiffs filed a status report indicating they will circulate a stipulation
for dismissal without prejudice.

   A qui tam action (one in which the plaintiff sues for the government as well
as for itself, and gets to keep part of the recovery) was brought by Jack
Grynberg, an oil and gas entrepreneur, against a major part of the gas
industry, including the Company and several of its subsidiaries. The complaint,
which was filed on July 2, 1997, was under seal pending Department of Justice
review. The Department of Justice declined to intervene and the seal was lifted
in May 1999. The Company was served in the Western District of Louisiana on May
1, 1999. The suit alleges fraudulent mismeasurement of gas volumes and
underreporting of gas royalties from gas production taken from federal leases.
The cases have been removed to the Eastern District of Wyoming, where a motion
to dismiss will be filed by the Company.

                                       14
<PAGE>

   A class action was filed by Quinque Operating Co. and others against
approximately 300 defendants, including the Company and several of its
subsidiaries, in Stevens County, Kansas. The complaint, which was served on
the Company and its subsidiaries on September 24, 1999, alleged fraud,
misrepresentation, conversion and assorted other claims, in the measurement
and payment of gas royalties from privately held gas leases. The case has been
remanded to Kansas state court by the federal judge overseeing the Grynberg
case. The plaintiffs will seek class certification and expedited discovery in
Kansas. The defendants in the case have filed a motion to keep the case in
federal court.

   The Company believes the above complaints to be without merit. Management
believes that the ultimate resolution of the issues will not have a material
adverse effect on the Company's financial position, results of operations or
cash flows.

   The Company has solicited and received the necessary consents from bond
holders for proposed amendments to the 1971 Indenture under which its 5 3/4
percent debentures due August 1, 2003 and its 6 5/8 percent debentures due
December 1, 2013 aggregating $300 million in principal amount were issued. The
proposed amendments are designed to conform the 1971 Indenture more closely to
the Company's 1995 Indenture, under which $1.35 billion of debt securities are
currently outstanding. Execution of a supplemental indenture implementing the
amendments is also conditioned upon effectiveness of a SEC order permitting
the proposed amenmdments under the 1935 Act. We are currently awaiting such
order approving the proposed amendments.

   See Note 19 to the Consolidated Financial Statements for additional
discussion on environmental matters.

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

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

                                      15
<PAGE>

                                    PART II

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

   Prior to the January 28, 2000 merger with Dominion, the Company's common
stock was publicly traded. The principal market for the stock was the New York
Stock Exchange. At December 31, 1999, there were 30,659 holders of the
Company's common stock. Quarterly price ranges on the common stock for the year
1999, and for the period January 1 through January 27, 2000, are shown in the
following table. Effective with the January 28, 2000 merger, Dominion owns all
the Company's common stock.

<TABLE>
<CAPTION>
                                                    Quarter
                                           ------------------------------------
Market Price Range:                        First      Second    Third    Fourth
-------------------                        -----      ------    -----    ------
<S>                                        <C>        <C>       <C>      <C>
2000--High................................ $68 1/2     n/a       n/a      n/a
  --Low................................... $63 9/16    n/a       n/a      n/a
1999--High................................ $57 3/4     $61 3/16 $64 1/8   $65 7/16
  --Low................................... $48 11/16   $48 1/2  $60 5/8   $61 7/8
</TABLE>

   Cash dividends paid by the Company on its common stock during the years 2000
and 1999 are presented below. The dividends in 1999, and $47 million of the
amount in the first quarter of 2000, were paid to the Company's former public
shareholders at the rate of $.485 a share. The remainder of the dividends paid
during the year 2000 was paid to Dominion. Restrictions on the payment of
dividends by the Company are discussed in Note 17 to the consolidated financial
statements.

<TABLE>
<CAPTION>
                                                                Quarter
                                                       -------------------------
                                                       First Second Third Fourth
                                                       ----- ------ ----- ------
                                                              (Millions)
Dividends Paid:
---------------
<S>                                                    <C>   <C>    <C>   <C>
2000..................................................  $93  $ --   $ --   $611
1999..................................................  $46  $  46  $  47  $ 47
</TABLE>

                        ITEM 6. SELECTED FINANCIAL DATA

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

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

Forward-Looking Information

   This Management's Discussion and Analysis of Results of Operations contains
"forward-looking statements" as defined by the Private Securities Litigation
Reform Act of 1995, including (without limitation) discussions as to
expectations, beliefs, plans, objectives and future financial performance, or
assumptions underlying or concerning matters discussed in this document. These
discussions, and any other discussions, including certain contingency matters
(and their respective cautionary statements) discussed elsewhere in this
report, that are not historical facts, are forward-looking and, accordingly,
involve estimates, projections, goals, forecasts, assumptions and uncertainties
that could cause actual results or outcomes to differ materially from those
expressed in those forward-looking statements.

   The business and financial condition of Consolidated Natural Gas Company and
its subsidiaries (the Company) is influenced by a number of factors including
political and economic risks, market demand for

                                       16
<PAGE>

energy, inflation, capital market conditions, governmental policies,
legislative and regulatory actions (including those of the Federal Energy
Regulatory Commission (FERC), the Securities and Exchange Commission (SEC), the
Environmental Protection Agency (EPA), the Department of Energy, and the state
utility regulatory commissions in the states in which the Company operates),
industry and rate structure and legal and administrative proceedings. Some
other important factors that could cause actual results or outcomes to differ
materially from those discussed in the forward-looking statements include
changes in and compliance with environmental laws and policies, weather
conditions and catastrophic weather-related damage, present or prospective
wholesale and retail competition, competition for new energy development
opportunities, pricing and transportation of commodities, acquisition and
disposition of assets and facilities, exposure to changes in the fair value of
commodity contracts, counter-party credit risk and unanticipated changes in
operating expenses and capital expenditures. All such factors are difficult to
predict, contain uncertainties that may materially affect actual results, and
may be beyond the control of the Company. New factors emerge from time to time
and it is not possible for management to predict all such factors, nor can it
assess the impact of each such factor on the Company.

   Any forward-looking statement speaks only as of the date on which such
statement is made, and the Company undertakes no obligation to update any
forward-looking statement to reflect events or circumstances after the date on
which such statement is made.

Results of Operations

 Consolidated Net Income

   Net income in 2000 was $244 million, compared with net income of $137
million in 1999. Net income in 2000 includes $31 million for the cumulative
effect of the change in accounting for calculating the market-related value of
pension plan assets used to determine the expected return on pension plan
assets, a component of net periodic pension cost. (See Note 3 to the
consolidated financial statements for a discussion of this accounting change.)
Income before the cumulative effect of the accounting change was $213 million.
Significant factors affecting earnings in 2000 and 1999 include:

  . the sale of Virginia Natural Gas (VNG) which resulted in a gain of $163
    million ($98 million after taxes) in 2000 (see Note 6 to the consolidated
    financial statements);

  . the impairment of foreign investments held for sale which resulted in
    charges totaling $152 million ($99 million after taxes) (see Note 7 to
    the consolidated financial statements); and

  . restructuring and other merger-related costs in both 2000 and 1999. These
    charges totaled $270 million ($195 million after taxes) in 2000, and $213
    million ($145 million after taxes) in 1999 (see Note 6 to the
    consolidated financial statements).

   Earnings in the current year benefited from higher prices for gas, oil and
by-products, higher gas sales volumes by the local utilities due to colder
weather, increased gas production and lower operation expense. The lower
operation expense was due in large part to higher pension credits due to the
change in the method of accounting for calculating the market-related value of
pension plan assets. These positive factors were only partially offset by
increased depreciation and amortization expense and higher interest charges.

 Operating Revenue and Income

   Operating revenue includes revenue from regulated gas sales by the Company's
local distribution subsidiaries, nonregulated gas sales by the Company's
Appalachian supply marketing subsidiary and unregulated retail marketing
subsidiary, the transportation and storage of gas, gas and oil production, gas
and oil brokering activities and by-products operations. Total operating
revenue was $4.0 billion in 2000, an increase of $1.0 billion over revenue of
$3.0 billion in 1999.

   Regulated gas sales revenue was $1.7 billion in 2000, an increase of $322
million compared to $1.4 billion in 1999. Regulated gas sales volumes were 224
billion cubic feet (Bcf), an increase of 3 Bcf compared to 1999.

                                       17
<PAGE>

Due to the sale of VNG in 2000, sales revenue and volumes in the current year
include only nine months of activity for this subsidiary compared to a full
year for 1999. The increase in sales volumes reflects higher sales to
residential and commercial customers due to the colder weather experienced in
the latter part of 2000. Average sales rates for all customer groups increased
sharply, reflecting the pass through of higher purchased gas costs. Nationally,
natural gas prices have more than tripled in the past 12 months, with colder-
than-normal weather in November and December causing much of the increase.

   Nonregulated gas sales revenue was $675 million in 2000, compared to $211
million in 1999. The increase is attributable to both higher sales volumes and
higher prices. The increased sales volumes reflect, in part, the transfer of
gas marketing operations from Dominion to the Company in May of 2000.

   Gas transportation and storage revenue totaled $551 million in 2000, down
$16 million compared to $567 million in 1999. Gas transportation revenue was
down $23 million in 2000, to $420 million. The decrease reflects primarily
changes in amounts reserved for rate contingencies as compared to 1999. Storage
service revenue was $131 million in 2000, compared with $124 million in 1999.

   Gas and oil production revenue, which represents revenue from sales of the
Company's equity production, totaled $532 million in 2000, an increase of $163
million compared with $369 million in 1999. Gas production revenue was $399
million in 2000, up $137 million compared with 1999. Revenue in the current
year reflects sharply higher natural gas prices and increased production. Oil
and condensate production revenue was $133 million in 2000, compared to $107
million in 1999. Higher prices in the current year more than offset lower
production.

   Other operating revenue increased $105 million in 2000, to $535 million.
Revenue from brokered gas and oil activities was $327 million in 2000, up $61
million compared to $266 million in 1999. Higher gas and oil prices was the
primary reason for the increase. Revenue from the sale of products extracted
from natural gas increased $32 million in 2000, to $94 million, as higher by-
product prices more than offset lower sales volumes.

 Operating Expenses

   Total operating expenses were $3.5 billion in 2000 and $2.6 billion in 1999.

   Purchased gas represents the largest expense category for the Company, and
relates to volumes purchased to meet sales requirements for regulated and
nonregulated operations, including gas brokering activities. This expense is
influenced primarily by changes in gas sales requirements, the price of gas
supplies, and the timing of recoveries of deferred purchased gas costs by the
rate-regulated subsidiaries. Purchased gas costs were $1.7 billion in 2000, up
$793 million compared to $912 million in 1999. The increase in 2000 is due to a
combination of increased volume requirements and significantly higher purchase
prices. The increased volume requirements reflect both the previously mentioned
transfer of gas marketing operations from Dominion, and colder weather in the
Company's retail service area in 2000. The higher purchased gas prices mirror
the dramatic increase in natural gas prices nationwide.

   Liquids, capacity and other products purchased expense includes the cost of
oil, condensate and by-products purchased for resale, electricity purchased for
resale and pipeline capacity not associated with purchased gas. This expense
increased $48 million in 2000, to $328 million, due primarily to increased
prices for oil purchased to satisfy brokered oil sales.

   Restructuring and other merger-related costs of $270 million in 2000 and
$213 million in 1999 were incurred in connection with the acquisition of the
Company by Dominion (see Note 6 to the consolidated financial statements).

   Operation and maintenance expense was $586 million in 2000, down $87 million
compared to $673 million in 1999. This decrease reflects higher pension credits
due to the change in the method of accounting for

                                       18
<PAGE>

calculating the market-related value of pension plan assets and lower labor
costs. The lower labor costs were the result of restructuring initiatives
following the merger, including an involuntary severance program and a
voluntary early retirement program. These lower costs were offset, to an
extent, by increased reserves for uncollectible accounts and administrative and
corporate support costs provided by Dominion's services company not present in
the prior year. In addition, maintenance expense decreased reflecting the
completion of workover activities at one of the Company's deepwater properties
in 1999.

   Depreciation and amortization increased $64 million in 2000, to $443
million, due chiefly to the acquisition of additional producing properties in
late 1999 and in 2000.

   Other taxes increased $6 million, to $203 million in 2000. Higher Ohio
excise taxes were only partially offset by the discontinuance of Pennsylvania
gross receipts tax as of January 1, 2000, and decreases in other miscellaneous
taxes. This decrease in gross receipts taxes was accompanied by a decrease in
revenue as customer collections for this tax ceased for gas services provided
on or after January 1, 2000.

 Other Income and Expense

   Other income and expense includes the pretax gain on the sale of VNG of $163
million. The Company was required to spin-off or sell VNG pursuant to
conditions set forth by the Virginia State Corporation Commission and Federal
Trade Commission in connection with their approval of the acquisition of the
Company by Dominion (see Note 6 to the consolidated financial statements).
Other income and expense also includes a $152 million pretax loss representing
impairments of CNG International's Australian and Argentine investments, and
the accrual for a probable equity contribution associated with the Australian
investments (see Note 7 to the consolidated financial statements). Other income
was $34 million in 2000, as compared to $14 million in 1999. Interest revenue
was higher in the current year due to higher earnings on hedge-related
brokerage accounts. Other income also increased in the current year due in part
to higher income from equity and other investments.

 Interest Charges

   Total interest charges were $162 million in 2000, compared to $124 million
in 1999. Interest on long-term debt increased $15 million in 2000, to $123
million. The increase reflects the issuance of $400 million of 7 1/4% notes in
September 1999, partially offset by the redemption, at maturity, of $100
million of 8 3/4% debentures in June 1999, and the repayment of $45 million of
8 3/4% debentures due October 2019. The Company had no new long-term financing
in 2000. Other interest expense was $50 million, an increase of $21 million
compared to $29 million in 1999. The increase in 2000 is due primarily to
interest on commercial paper borrowings. Average borrowings during the year
were up approximately $225 million, while average interest rates rose 1.2
percent.

Segments of the Business

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

   Operating earnings for each of the Company's business segments, which
include affiliated transactions, follow. Reference is made to Note 22 to the
consolidated financial statements for additional segment information.

                                       19
<PAGE>

Income (Loss) From Operations

<TABLE>
<CAPTION>
                                                                 Years Ended
                                                                December 31,
                                                                --------------
                                                                 2000    1999
                                                                ------  ------
                                                                 (Millions)
<S>                                                             <C>     <C>
Distribution................................................... $  264  $  203
Transmission...................................................    235     209
Exploration and production.....................................    267     135
Other..........................................................     (6)     (6)
Corporate and eliminations.....................................   (283)   (221)
                                                                ------  ------
    Total...................................................... $  477  $  320
                                                                ======  ======
</TABLE>

 Distribution

   The Company's Distribution segment includes the results of its retail gas
distribution subsidiaries: The East Ohio Gas Company (Dominion East Ohio), The
Peoples Natural Gas Company (Dominion Peoples) and Hope Gas, Inc (Dominion
Hope). These subsidiaries sell gas and/or provide transportation services to
residential, commercial and industrial customers in Ohio, Pennsylvania and West
Virginia, and are subject to price regulation by their respective state utility
commissions. The Distribution segment also includes the results of VNG prior to
its sale to AGL Resources Inc. VNG provided gas sales and transportation
services to customers in Virginia, and is subject to price regulation by the
Virginia State Corporation Commission.

   Sales growth in the Company's residential service areas of Ohio,
Pennsylvania and West Virginia has generally been limited since such areas have
experienced minimal population growth, and the vast majority of households in
these areas already use natural gas for space heating. Sales are also being
affected by regulatory and legislative initiatives to deregulate natural gas at
the retail level. Similar to the unbundling of the services provided by gas
pipeline companies, gas distribution companies are adapting to the deregulation
and unbundling of the retail energy market. Under open access programs in
Pennsylvania and Ohio, customers may now choose a gas supplier other than their
local gas utility, and have the local utility provide transportation of the
commodity through its existing delivery system.

   During 1997, Dominion Peoples opened its system in Pennsylvania to customer
choice. Also in 1997, The Public Utilities Commission of Ohio (PUCO) approved
the "Energy Choice" pilot program for certain customers of Dominion East Ohio.
Under the pilot program, approximately 15% of Dominion East Ohio's residential
and small business customers had the opportunity to purchase their natural gas
from competing suppliers. In the fall of 2000, the PUCO approved the expansion
of Energy Choice to the 1.2 million customers in the Dominion East Ohio service
area. At December 31, 2000, approximately 106,000 customers of Dominion Peoples
and 175,000 customers of Dominion East Ohio were participating in these open
access programs.

   Dominion Retail (formerly CNG Retail), the Company's nonregulated gas
marketing subsidiary, markets natural gas, electricity, and consumer products
and services to residential, commercial and small industrial customers,
including those within the Company's traditional retail service areas. Dominion
Retail is expected to enable the Company to take advantage of emerging
deregulated energy markets for both gas and electricity.

                                       20
<PAGE>

   The following table presents summarized information relating to the
Company's Distribution segment:

<TABLE>
<CAPTION>
                                                          Years Ended December
                                                                   31,
                                                          ---------------------
Distribution Operations                                      2000       1999
-----------------------                                   ---------- ----------
                                                               (Millions)
<S>                                                       <C>        <C>
Operating revenue and income............................. $    1,982 $    1,640
Income from operations...................................        264        203

<CAPTION>
                                                          (Billion Cubic Feet)
<S>                                                       <C>        <C>
Throughput:
  Gas sales..............................................        224        221
  Gas transportation.....................................        209        209
                                                          ---------- ----------
    Total throughput.....................................        433        430
                                                          ========== ==========
</TABLE>

 Operating Revenue and Income from Operations

   Operating revenue increased $342 million in 2000 to almost $2.0 billion.
Regulated gas sales revenue was $1.7 billion, an increase of $322 million over
$1.4 billion in 1999. Due to the sale of VNG in 2000, sales revenue in the
current year includes only nine months of activity for this subsidiary
compared to a full year for 1999. The increased revenue in 2000 reflects
colder weather experienced in the Company's retail service areas and higher
sales rates. Weather in the Company's retail service areas was 1% warmer than
normal, but 8% colder than in 1999. Average sales rates for all customer
groups increased sharply, reflecting the pass through of higher purchased gas
costs. Nationally, natural gas prices have more than tripled in the past 12
months, with colder-than-normal weather in November and December causing much
of the increase. Gas transportation and storage revenue increased $13 million
in 2000, to $222 million. The increase was due primarily to higher gas
transportation volumes, reflecting the continued migration of residential and
commercial customers from sales to transport service under customer choice
programs.

   Income from operations was $264 million in 2000, an increase of $61 million
compared to $203 million in 1999. Higher revenue and lower operating costs
were the principal reasons for the improved results. The lower operating costs
reflect higher pension credits due to the change in the method of accounting
for calculating the market-related value of pension plan assets and lower
labor costs. The lower labor costs were the result of restructuring
initiatives following the merger, including an involuntary severance program
and a voluntary early retirement program. These lower costs were offset, to an
extent, by increased reserves for uncollectible accounts, higher Ohio excise
taxes and administrative and corporate support costs provided by Dominion's
services company not present in the prior year.

 Distribution Throughput

   Since Distribution sales volumes largely represent gas used for space
heating, changes in volumes are primarily a function of the weather. In
addition to sales service, the Distribution segment provides gas
transportation services to a wide range of customers, including residential,
commercial and industrial end users. Therefore, the volume of gas transported
can be affected by the weather and by changes in both economic and market
conditions. Both gas sales and transportation volumes are also being impacted
by the migration of customers from sales to transport service under customer
choice programs.

   Gas sales volumes were 224 Bcf in 2000 compared to 221 Bcf in 1999. The
year-to-year comparison reflects increased sales in 2000 due to colder weather
in the latter part of the year, the loss of sales due to the migration of
customers from sales to transport under customer choice programs, and the
absence of fourth quarter sales for VNG in 2000 due to the sale of that
subsidiary. Residential gas sales volumes increased 2 Bcf

                                      21
<PAGE>

in 2000, to 173 Bcf, while volumes transported for residential customers
increased 10 Bcf. Sales to commercial customers were 48 Bcf in 2000, unchanged
from 1999, while volumes transported to these customers were down 2 Bcf to 41
Bcf. Total deliveries to industrial customers were 134 Bcf in 2000, compared
to 143 Bcf in 1999. Industrial transport volumes in 2000 were down 9 Bcf, to
131 Bcf, while sales were 2 Bcf, unchanged from the prior year.

 Transmission

   The Transmission segment includes certain operations of Dominion
Transmission (formerly CNG Transmission), the operations of Dominion Field
Services (formerly CNG Field Services), and the gas by-products business of
CNG Power. Dominion Transmission, an interstate pipeline company regulated by
the Federal Energy Regulatory Commission (FERC), provides gas transportation,
storage and related services to affiliates and to utilities and end users in
the Midwest, the Mid-Atlantic states and the Northeast. The gas and oil
production activities of Dominion Transmission are included in the Exploration
and Production segment. Dominion Field Services is engaged in activities
related to Appalachian area natural gas supply, and provides natural gas
storage facilities and services and other activities of a full service gas
storage business. Prior to 2000, the results of Dominion Field Services were
included in "Other." As a result of the change, segment information for prior
years has been restated. Although the Transmission segment includes the gas
by-products business of CNG Power, this subsidiary effectively exited that
business during 2000.

   The following table presents summarized information relating to the
Company's Transmission segment:

<TABLE>
<CAPTION>
                                                          Years Ended December
                                                                   31,
                                                          ----------------------
Transmission Operations                                      2000       1999
-----------------------                                   ----------- ----------
                                                               (Millions)
<S>                                                       <C>         <C>
Operating revenue and income............................. $     1,135 $     654
Income from operations...................................         235       209

<CAPTION>
                                                          (Billion Cubic Feet)
<S>                                                       <C>         <C>
Throughput:
  Gas sales..............................................         156        53
  Gas transportation.....................................         656       647
                                                          ----------- ---------
    Total throughput.....................................         812       700
                                                          =========== =========
</TABLE>


 Operating Revenue and Income from Operations

   Total operating revenue of the Transmission segment was $1.1 billion in
2000, compared to $654 million in 1999. Gas transportation revenue was $284
million, down $36 million from 1999, primarily as a result of changes in
amounts reserved for possible rate contingencies. Storage service revenue was
$154 million, up $6 million compared to $148 million in 1999. Nonregulated gas
sales revenue was $617 million, up $481 million from 1999 as a result of
higher sales volumes due to the transfer of Dominion's gas marketing
operations in May of 2000, a higher level of activity, and significantly
higher sales prices in 2000. Of the increase, $339 million is attributable to
the transfer of Dominion's gas marketing operations. Average sales prices were
$3.96 per thousand cubic feet (Mcf) in 2000, compared to $2.59 per Mcf in
1999. Revenue from the sale of natural gas by-products was $78 million in
2000, an increase of $31 million from $47 million in 1999. Although by-
products sales volumes were down slightly, average sales prices for all
products nearly doubled in 2000.

   Income from operations was $235 million in 2000, compared to $209 million
in 1999. Higher revenue and lower operating costs were the principal reasons
for the improved results. The lower operating costs reflect higher pension
credits due to the change in the method of accounting for calculating the
market-related value of

                                      22
<PAGE>

pension plan assets and lower labor costs. The lower labor costs were the
result of restructuring initiatives following the merger, including an
involuntary severance program and a voluntary early retirement program. These
lower costs were offset, to an extent, by administrative and corporate support
costs provided by Dominion's services company not present in the prior year.

 Transmission Throughput

   Gas transportation volumes increased 9 Bcf in 2000, to 656 Bcf, primarily as
a result of the colder weather experienced in the latter part of the year. Gas
sales volumes in 2000 were 156 Bcf, up 103 Bcf over 1999. Of the sales volume
increase, 89 Bcf was due to the transfer of gas marketing operations from
Dominion.

 Exploration and Production

   The Exploration and Production segment includes the results of Dominion
Exploration & Production (formerly CNG Producing) and the gas and oil
production activities of Dominion Transmission. The activities of Dominion
Exploration & Production are conducted primarily in the Gulf of Mexico, the
southern and western United States, the Appalachian region and in Canada.
However, Dominion Exploration & Production's Canadian properties were
transferred by sale to another subsidiary of Dominion effective January 1,
2001. Also included in this segment are CNG Main Pass Gas Gathering and CNG Oil
Gathering. These two subsidiaries hold equity investments in gas and oil
gathering systems located in the Gulf of Mexico.

   During 2000, Dominion Exploration & Production acquired 167 billion cubic
feet equivalent of gas reserves and additional acreage for exploratory and
development drilling through a number of purchase transactions. Significant
acquisitions during the year included the purchase of additional interests in
two deepwater Gulf of Mexico properties and various South Texas gas fields. In
January 2000, Dominion Exploration & Production acquired an additional 12.5
percent interest in Popeye, a deepwater gas producing property, increasing its
interest to 50 percent. Dominion Exploration & Production also doubled its
interest in the Devil's Tower deepwater discovery to 60 percent. In August
2000, Dominion Exploration & Production acquired the operating interests of
Suemaur Exploration & Production, LLC and several partners in three Texas Gulf
Coast natural gas fields. The total amount spent on exploration and production
acquisitions during the year ended December 31, 2000, was $218 million.

   The following table sets forth information relating to the Company's
Exploration and Production segment, including gas and oil production, average
wellhead prices and other information:

<TABLE>
<CAPTION>
                                                                     Years Ended
                                                                    December 31,
                                                                    -------------
Exploration and Production Operations                                2000  1999*
-------------------------------------                               ------ ------
                                                                     (Millions)
<S>                                                                 <C>    <C>
Operating revenue and income....................................... $1,016 $  753
Income from operations.............................................    267    135
Production:
  Gas (Bcf)........................................................    173    153
  Oil (000 Bbls)...................................................  7,213  8,545
Average Wellhead Prices:
  Gas (per Mcf).................................................... $ 3.08 $ 2.26
  Oil (per Bbl)....................................................  18.60  12.67
Other Information:
  DD&A (per Mcf equivalent)........................................ $ 1.30 $ 1.13
  Average production (lifting) cost (per Mcf equivalent)........... $  .43 $  .40
</TABLE>
--------
*  Production, average wellhead prices and other information has been restated
   from a "net before royalty" basis to a "net revenue" basis.

                                       23
<PAGE>

 Operating Revenue and Income from Operations

   Gas and oil production revenue was $633 million in 2000, up $205 million
compared to $428 million in 1999. Gas production revenue was $500 million in
2000, up $179 million, and oil production revenue was $133 million, up $26
million. Following the nationwide trend in energy prices, the average wellhead
prices for both gas and oil were significantly higher in 2000. Gas production
increased 20 Bcf due to property acquisitions during the year and accelerated
development spending. Oil production was down 1.3 million barrels due primarily
to natural production declines at the Neptune deepwater field and other older
properties. Revenue from gas and oil brokering activities was $327 million in
2000, up $61 million from 1999. While transaction volumes for brokering
activities were lower, prices were up significantly.

   Income from operations was $267 million in 2000, up $132 million compared to
$135 million in 1999. Higher revenue more than offset the increased costs for
gas and oil purchased in connection with brokering activities, and increased
depreciation and amortization expense. The higher depreciation and amortization
expense was attributable to increased gas production volumes and new properties
acquired during 2000.

 Other

   The Other segment includes the results of Dominion Retail, Dominion Products
and Services (formerly CNG Products and Services), CNG International and other
minor subsidiaries of the Company. Dominion Retail, a nonregulated company,
markets natural gas, electricity and related products and services to
residential, commercial and small industrial customers. Dominion Products and
Services provides energy-related services to customers of the Company's local
distribution subsidiaries and others. CNG International is engaged in energy-
related activities outside the United States. However, the Company has decided
to focus on United States oil and gas markets and, accordingly, is pursuing the
sale of CNG International (see Note 7 to the consolidated financial
statements).

   Summarized information regarding this segment follows:

<TABLE>
<CAPTION>
                                                                   Years Ended
                                                                    December
                                                                       31,
                                                                   ------------
Other Operations                                                   2000   1999
----------------                                                   -----  -----
                                                                   (Millions)
<S>                                                                <C>    <C>
Operating revenue and income...................................... $ 186  $ 131
Income (loss) from operations.....................................    (6)    (6)

<CAPTION>
                                                                    (Billion
                                                                   Cubic Feet)
<S>                                                                <C>    <C>
Gas sales.........................................................    40     34
</TABLE>

 Operating Revenue and Income from Operations

   Nonregulated gas sales revenue of the Other segment was $148 million in
2000, up from $103 million in 1999. Electricity sales revenue was $19 million,
compared to $9 million in 1999. The loss from operations for this segment was
$6 million in both 2000 and 1999. A substantial portion of the loss from
operations is attributable to CNG International, which derives most of its
earnings from equity investments.

Limitation on Capitalized Costs

   As indicated in Note 2 to the consolidated financial statements, the Company
follows the full cost method of accounting for its gas and oil producing
activities. Under this method, the total capitalized costs, net of related
deferred taxes, are subject to a limitation based on the present value of
estimated future net revenue expected to be received from the production of
proved reserves. If net capitalized costs exceed this amount at the end of any
quarter, a permanent impairment of the assets must be recognized in that
period.

                                       24
<PAGE>

   There are a number of factors, including prices, that determine whether or
not an impairment is required. Both gas and oil prices were at extremely high
levels at the end of 2000, and have remained at high levels in the early part
of 2001. However, gas prices are subject to sudden and seasonal fluctuations,
and oil prices are subject to sudden change in response to both domestic and
global events and trends. As a result, the impairment of these gas and oil
properties is a possibility at any quarterly measurement date, unless other
factors such as proved reserve additions or lower costs mitigate the impact of
a price decline.

Environmental Matters

   The Company is subject to various federal, state and local laws and
regulations relating to the protection of the environment. These laws and
regulations govern both current and future operations and potentially extend to
plant sites formerly owned or operated by the subsidiaries, or their
predecessors.

   Reference is made to Note 19 to the consolidated financial statements for a
detailed description of environmental matters.

   Estimates of liability in the environmental area are based on current
environmental laws and regulations and existing technology. The exact nature of
environmental issues which the Company may encounter in the future cannot be
predicted. Additional environmental liabilities may result in the future as
more stringent environmental laws and regulations are implemented and as the
Company obtains more specific information about its existing sites and
production facilities. At present, no estimate of any such additional
liability, or range of liability amounts, can be made. However, the amount of
any such liabilities could be material.

Effects of Inflation

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

Recently Issued Accounting Standards

   In June 2000, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 138, Accounting for
Certain Derivative Instruments and Certain Hedging Activities, which amends
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities.
SFAS No. 133 requires that all derivative instruments be recorded on the
Company's balance sheet at their fair value effective January 1, 2001.

   The Company has determined that certain contracts used in its operations
will be subject to fair value accounting under SFAS No. 133. A substantial
portion of these contracts is used by the Company in its production and
delivery of energy to its customers and the contracts involve various hedging
strategies. In addition to these commodity contracts, the Company uses interest
rate swaps to manage its cost of capital.

   The Company will record one-time, non-operating after-tax charges to net
income of approximately $14 million and other comprehensive income of
approximately $102 million in the first quarter of 2001 for the initial
adoption of SFAS No. 133. These adjustments will be recognized as of January 1,
2001 as the cumulative effect of a change in accounting principle. The ongoing
effects will depend on future market conditions, the Company's hedging
activities, and further interpretations of the standard. The Derivatives
Implementation Group (DIG), a group sponsored by the FASB, continues to develop
interpretive guidance. The DIG has not yet resolved certain issues that could
ultimately impact the application of the standard.

                                       25
<PAGE>

Other Information

 2000 Restructuring and Other Merger-Related Costs

   Following the merger of Dominion and the Company, Dominion and its
subsidiaries developed and began the implementation of a plan to restructure
the operations of the combined companies. Restructuring activities include
workforce reductions and the consolidation of post-merger operations and
information technology systems. For the year ended December 31, 2000, the
Company recognized $270 million of restructuring and other merger-related costs
as discussed below:

 Workforce Reductions

   Under the restructuring plan, a total of 434 positions at the Company and
its subsidiaries have been identified for elimination and the Company has
recorded $31 million in employee severance related costs. At December 31, 2000,
a total of 373 positions had been eliminated, and $18 million of severance
benefits had been paid.

   During the second quarter of 2000, approximately 450 employees elected to
participate in the early retirement program (ERP), resulting in an expense
approximating $62 million. This expense was offset, in part, by curtailment
gains of $26 million attributable to reductions in expected future years of
service as a result of ERP participation and involuntary employee terminations.

 Other Restructuring and Merger-Related Costs

   In connection with the implementation of Dominion's new enterprise-wide
price risk management strategy, the Company designated its portfolio of
derivative contracts that existed at January 28, 2000 as held for purposes
other than hedging for accounting purposes and entered into "offsetting"
contracts for those contracts in the January 28, 2000 portfolio that would not
be settled during the first quarter of 2000. The mark-to-market accounting for
these contracts held for purposes other than hedging resulted in the
recognition of losses of $55 million for the year ended December 31, 2000. Due
to the Company's establishing the offsetting portfolio of derivative contracts,
absent any not yet identified future losses from credit risk exposure, no
additional material losses are expected to be realized as these derivative
contracts mature through 2003. See Note 20 to the consolidated financial
statements for further discussion.

   Other merger-related costs charged during the year ended December 31, 2000
totaled $148 million and included settlement of certain employment contracts
and payments under seismic licensing agreements due to change of control,
merger-related transaction costs and fees, lease termination and restructuring
costs, and excess amortization expense attributable to shortening the useful
lives of capitalized software being impacted by systems integration and related
conversion costs.

   The planned workforce reductions and the accelerated amortization in 2000 of
information technology systems that will be abandoned should avoid future
annualized operating costs of approximately $62 million that would have
otherwise been incurred.

 Sale of Virginia Natural Gas

   On October 6, 2000, the Company completed the sale of VNG to AGL Resources
Inc. Cash proceeds from the sale amounted to $533 million, resulting in a gain
of $163 million ($98 million after taxes). The Company was required to spin-off
or sell VNG pursuant to conditions set forth by the Virginia State Corporation
Commission and Federal Trade Commission in connection with their approval of
the acquisition of the Company by Dominion. See Note 6 to the consolidated
financial statements for further information.

 1999 Restructuring and Other Merger-Related Costs

   During the second quarter of 1999, the Company recorded a charge of $154
million for compensation expenses associated with the cash settlements of
vested stock options and other stock awards pursuant to

                                       26
<PAGE>

change of control provisions in the Company's then effective stock incentive
plans in connection with the approval by shareholders of the merger with
Dominion. In addition, the Company recorded charges for the costs related to
certain executive employment agreements and for other merger costs, including
direct incremental costs (including fees of financial advisors, legal counsel
and other costs). These charges totaled $59 million for the year ended December
31, 1999.

   See Note 6 to the consolidated financial statements for further discussion
of 2000 and 1999 restructuring and other merger-related costs.

 Impairment of International Investments

   CNG International has been engaged in energy-related activities outside of
the United States, primarily through equity investments in Australia and
Argentina. Consistent with its strategy to focus on its core business, in the
first quarter of 2000, management committed to a plan of disposal for CNG
International. The Company recognized losses related to CNG International for
the year ended December 31, 2000 of $152 million ($99 million after tax). The
Company believes it is probable that, as part of a sale of its Australian
investments, it will be required to make a $100 million equity contribution
pursuant to the Equity Contribution Agreement discussed in Note 7 to the
consolidated financial statements.

   On October 12, 2000, CNG International completed the sale of its Argentine
assets to Sempra Energy International, a subsidiary of Sempra Energy for $145
million in cash.

Gas and Electric Industry Developments

 Federal

   The United States Congress has considered legislation to conditionally
repeal the Public Utility Holding Company Act of 1935 (PUHCA), to which the
Company is subject. While it seems unlikely that Congress will enact PUHCA
legislation on a stand-alone basis, it appears more likely that any
comprehensive electric restructuring bill will include a PUHCA repeal
provision. If legislation to repeal or significantly modify the provisions of
the PUHCA becomes law, certain federal restrictions related to diversification
activities, including business combinations, for gas and electric companies
subject to the PUHCA may be eased.

 State Deregulation Legislation

   Each of the three states in which the Company has gas distribution
operations have enacted or considered legislation regarding deregulation of
natural gas sales at the retail level.

 Pennsylvania

   As early as 1984, large industrial customers in Pennsylvania began to buy
natural gas supplies from third parties, rather than directly from local
utilities; the local distributors transported these third-party gas supplies to
the industrial facilities. Since that time, nearly all Pennsylvania industrial
and large commercial customers have changed from utility sales customers to
transportation services customers, buying the natural gas commodity from
unregulated suppliers and transporting it on our own gas delivery network. In
1997, Dominion Peoples, the Company's Pennsylvania gas utility, voluntarily
launched an Energy Choice program for all of its retail consumers in
Pennsylvania -- whether industrial, commercial, or residential. Subsequently,
in 1999, Pennsylvania enacted legislation to mandate supplier choice for
residential and small commercial customers. At December 31, 2000, approximately
106,000 customers had opted for Energy Choice in the Company's Pennsylvania
service area.

 Ohio

   Large industrial customers in Ohio began to source their own natural gas
supplies in the mid-1980s, as interstate pipeline transportation services
became more widely available. However, to date Ohio has not

                                       27
<PAGE>

enacted legislation to require supplier choice for residential and commercial
natural gas consumers. Dominion East Ohio has made significant progress in
offering Energy Choice to customers on its own initiative, in cooperation with
The Public Utilities Commission of Ohio. In 1997, Dominion East Ohio launched a
pilot program designed to make gas transportation service available to
residential and small commercial customers, and to the suppliers that market
gas to these customer classes. In 2000, the Energy Choice program was expanded
to all 1.2 million customers in the Company's Ohio service area. At December
31, 2000, approximately 175,000 customers of Dominion East Ohio were
participating in this open access program.

 West Virginia

   At this time, West Virginia has not enacted legislation to require customer
choice in its retail natural gas markets. In this smaller, more rural market
area, Dominion Hope has not voluntarily initiated an energy choice program.
However, the West Virginia Public Service Commission recently issued
regulations to govern pooling services; these services are one of the tools
that natural gas suppliers may utilize to provide retail customer choice in the
future.

Market Rate Sensitive Instruments and Risk Management

   The Company is exposed to market risk because it utilizes financial
instruments, derivative financial instruments and derivative commodity
instruments. The market risks inherent in these instruments are represented by
the potential loss due to adverse changes in commodity prices and interest
rates as described below. Interest rate risk generally is related to the
Company's outstanding debt. Commodity price risk is experienced in the
Company's gas production and procurement operations, and energy marketing and
trading operations due to the exposure to market shifts for prices received and
paid for natural gas and oil. The Company uses derivative commodity instruments
to hedge price exposures for these operations.

   During 2000, the Company changed its method of presentation for risk
disclosure to the sensitivity analysis methodology in order to conform to the
method used by Dominion. The sensitivity analysis estimates the potential loss
of future earnings or fair value from market risk sensitive instruments over a
selected time period due to a 10% unfavorable change in interest rates and
commodity prices. As a result of the change, information presented for 1999 has
been provided on a comparable basis.

 Interest Rate Risk

   In March 2000, the Company entered into an interest rate swap agreement to
manage its interest rate risk exposure. For the interest rate swap agreement
outstanding at December 31, 2000, a hypothetical 10% increase in market
interest rates would decrease annual earnings by approximately $2 million.

 Commodity Price Risk

   The Company manages the price risk associated with purchases and sales of
natural gas and oil by selecting derivative commodity instruments including
futures, forwards, options, swaps and collars.

   For sensitivity analysis purposes, the fair value of the Company's oil and
natural gas derivative financial contracts are determined from models which
take into account the market prices of oil and natural gas in future periods,
the volatility of the market prices in each period, as well as the time value
factors of the underlying commitments. In most instances, market prices and
volatility are determined from quoted prices on the futures exchange.

   The Company has determined a hypothetical change in fair value for its oil
and natural gas derivative financial contracts assuming a 10% unfavorable
change in market prices. This hypothetical 10% change in market prices would
have resulted in a decrease in fair value of approximately $52 million and $46
million as of December 31, 2000 and December 31, 1999, respectively.

   The impact of a change in oil and natural gas commodity prices on the
Company's oil and natural gas derivative financial contracts at a point in time
is not necessarily representative of the results that will be

                                       28
<PAGE>

realized when such contracts are ultimately settled. Net losses from oil and
natural gas financial derivative contracts used for hedging purposes, to the
extent realized, should generally be offset by the recognition of the hedged
transaction.

 Risk Management Policies

   The Company has operating procedures in place that are administered by
experienced management to help ensure that proper internal controls are
maintained. In addition, Dominion has established an independent function at
the corporate level to monitor compliance with the price risk management
policies of all subsidiaries. Dominion maintains credit policies that include
the evaluation of a prospective counterparty's financial condition, collateral
requirements where deemed necessary, and the use of standardized agreements
which facilitate the netting of cash flows associated with a single
counterparty. Dominion also monitors the financial condition of existing
counterparties on an ongoing basis. The Company believes it unlikely that a
material adverse effect on its financial position, results of operations or
cash flows would occur as a result of counterparty nonperformance.

      ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

   See Market Rate Sensitive Instruments and Risk Management under MANAGEMENT'S
DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS.

                                       29
<PAGE>

              ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                                     INDEX

<TABLE>
<CAPTION>
                                                                      Page No.
                                                                      --------
<S>                                                                   <C>
Report of Management.................................................    31

Reports of Independent Auditors......................................    32

Consolidated Statements of Income for the years ended December 31,
 2000, 1999 and 1998.................................................    34

Consolidated Balance Sheets at December 31, 2000 and 1999............    35

Consolidated Statements of Cash Flows for the years ended December
 31, 2000, 1999 and 1998.............................................    36

Consolidated Statements of Comprehensive Income for the years ended
 December 31, 2000, 1999 and 1998....................................    38

Notes to Consolidated Financial Statements...........................    39
</TABLE>

                                       30
<PAGE>

                              REPORT OF MANAGEMENT

   The Company's management is responsible for all information and
representations contained in the Consolidated Financial Statements and other
sections of the Company's annual report on Form 10-K. The Consolidated
Financial Statements, which include amounts based on estimates and judgments of
management, have been prepared in conformity with generally accepted accounting
principles. Other financial information in the Form 10-K is consistent with
that in the Consolidated Financial Statements.

   Management maintains a system of internal accounting controls designed to
provide reasonable assurance, at a reasonable cost, that the Company's assets
are safeguarded against loss from unauthorized use or disposition and that
transactions are executed and recorded in accordance with established
procedures. Management recognizes the inherent limitations of any system of
internal accounting control and, therefore, cannot provide absolute assurance
that the objectives of the established internal accounting controls will be
met.

   This system includes written policies, an organizational structure designed
to ensure appropriate segregation of responsibilities, careful selection and
training of qualified personnel, and internal audits. Management believes that
during 2000 the system of internal control was adequate to accomplish the
intended objectives.

   The Consolidated Financial Statements for the year ended December 31, 2000
have been audited by Deloitte & Touche LLP, independent auditors, who were
designated by the Board of Directors. The Consolidated Financial Statements for
the years ended December 31, 1999 and 1998 have been audited by
PricewaterhouseCoopers LLP, independent accountants. Their audits were
conducted in accordance with auditing standards generally accepted in the
United States of America and include a review of the Company's accounting
systems, procedures and internal controls, and the performance of tests and
other auditing procedures sufficient to provide reasonable assurance that the
Consolidated Financial Statements are not materially misleading and do not
contain material errors.

   The Audit Committee of the Board of Directors of Dominion Resources, Inc.
(the Company's parent), composed entirely of directors who are not officers or
employees of Dominion Resources, Inc. or its subsidiaries, meets periodically
with the independent auditors, the internal auditors and management to discuss
auditing, internal accounting control and financial reporting matters and to
ensure that each is properly discharging its responsibilities. Both the
independent auditors and the internal auditors periodically meet alone with the
Audit Committee and have free access to the Committee at any time.

   Management recognizes its responsibility for fostering a strong ethical
climate so that the Company's affairs are conducted according to the highest
standards of personal and corporate conduct. This responsibility is
characterized and reflected in Dominion's Code of Ethics, which addresses
potential conflicts of interest, compliance with all domestic and foreign laws,
the confidentiality of proprietary information, and full disclosure of public
information.

                        Consolidated Natural Gas Company

       /s/ Thomas N. Chewning                   /s/ Steven A. Rogers
           Thomas N. Chewning                       Steven A. Rogers
      Executive Vice President and           Vice President and Controller
         Chief Financial Officer             (Principal Accounting Officer)

                                       31
<PAGE>

                          INDEPENDENT AUDITORS' REPORT

The Board of Directors
Consolidated Natural Gas Company

   We have audited the accompanying consolidated balance sheet of Consolidated
Natural Gas Company (a wholly owned subsidiary of Dominion Resources, Inc.) and
subsidiaries (the "Company") as of December 31, 2000, and the related
consolidated statements of income, cash flows and comprehensive income for the
year then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audit.

   We conducted our audit in accordance with auditing standards generally
accepted in the United States of America. 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
audit provides a reasonable basis for our opinion.

   In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of the Company at December 31,
2000, and the results of its operations and its cash flows for the year then
ended in conformity with accounting principles generally accepted in the United
States of America.

   As discussed in Note 3 to the consolidated financial statements, the Company
changed its method of accounting used to develop the market-related value of
pension plan assets in 2000.

Deloitte & Touche LLP

Pittsburgh, Pennsylvania
January 25, 2001

                                       32
<PAGE>

                       REPORT OF INDEPENDENT ACCOUNTANTS

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

   In our opinion, the accompanying consolidated balance sheet as of December
31, 1999 and the related consolidated statements of income and comprehensive
income and of cash flows for each of the two years in the period ended December
31, 1999 present fairly, in all material respects, the financial position,
results of operations and cash flows of Consolidated Natural Gas Company and
subsidiaries at December 31, 1999 and for each of the two years in the period
ended December 31, 1999, in conformity with accounting principles generally
accepted in the United States of America. In addition, in our opinion, the
financial statement schedule listed in the index appearing under Item 14.(a).2.
on page 75 presents fairly, in all material respects, the information set forth
therein when read in conjunction with the related consolidated financial
statements. These financial statements and financial statement schedule are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements and financial statement schedule based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion. We have not audited the consolidated
financial statements of Consolidated Natural Gas Company for any period
subsequent to December 31, 1999.

                                          PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania
January 26, 2000

                                       33
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

                       CONSOLIDATED STATEMENTS OF INCOME

<TABLE>
<CAPTION>
                                                         For the Years Ended
                                                             December 31,
                                                         ---------------------
                                                          2000    1999   1998
                                                         ------  ------ ------
                                                              (Millions)
<S>                                                      <C>     <C>    <C>
Operating revenue and income:
  Regulated gas sales................................... $1,719  $1,397 $1,374
  Nonregulated gas sales................................    675     211    125
  Gas transportation and storage........................    551     567    546
  Oil and gas production................................    532     369    340
  Other.................................................    535     430    305
                                                         ------  ------ ------
    Total...............................................  4,012   2,974  2,690
                                                         ------  ------ ------
Expenses:
  Purchased gas.........................................  1,705     912    901
  Liquids, capacity and other products purchased........    328     280    145
  Restructuring and other merger-related costs..........    270     213    --
  Operation and maintenance.............................    586     673    638
  Depreciation and amortization.........................    443     379    330
  Other taxes...........................................    203     197    179
                                                         ------  ------ ------
    Total...............................................  3,535   2,654  2,193
                                                         ------  ------ ------
Income from operations..................................    477     320    497
                                                         ------  ------ ------
Other income and expense:
  Gain on sale of Virginia Natural Gas..................    163     --     --
  Loss on net assets held for sale......................   (152)    --     --
  Other.................................................     34      14     35
                                                         ------  ------ ------
    Total other income and expense......................     45      14     35
                                                         ------  ------ ------
Income from continuing operations before interest and
 income taxes...........................................    522     334    532
Interest charges........................................    162     124    114
                                                         ------  ------ ------
Income from continuing operations before income taxes...    360     210    418
Income tax expense......................................    147      73    130
                                                         ------  ------ ------
Income from continuing operations before cumulative
 effect of a change in accounting principle.............    213     137    288
                                                         ------  ------ ------
Discontinued operations:
  Loss from discontinued energy marketing services
   operations (net of income tax benefit of $9).........    --      --     (17)
  Loss from disposal of energy marketing services
   operations (net of income tax benefit of $17)........    --      --     (32)
                                                         ------  ------ ------
Income before cumulative effect of a change in
 accounting principle...................................    213     137    239
Cumulative effect of a change in accounting principle
 (net of income taxes of $11)...........................     31     --     --
                                                         ------  ------ ------
Net income.............................................. $  244  $  137 $  239
                                                         ======  ====== ======
</TABLE>

   The accompanying notes are an integral part of the Consolidated Financial
                                  Statements.

                                       34
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

                          CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
                                                               At December 31,
                                                               ---------------
                                                                2000    1999
                                                               ------- -------
                                                                 (Millions)
<S>                                                            <C>     <C>
                            ASSETS
                            ------
CURRENT ASSETS:
 Cash and cash equivalents.................................... $    58 $    94
 Accounts receivable:
   Customers (less allowance for doubtful accounts of $48 in
    2000 and $21 in 1999).....................................     740     415
   Other......................................................     253     112
 Receivables from affiliated companies........................      20     --
 Inventories:
   Gas stored--current portion................................      75      86
   Materials and supplies (average cost method)...............      21      20
 Unrecovered gas costs........................................     264      38
 Deferred income taxes--current (net).........................     --        1
 Broker margin deposits.......................................     264      22
 Prepayments..................................................     154     123
 Other........................................................     220     155
 Net assets held for sale.....................................      57     372
                                                               ------- -------
   Total current assets.......................................   2,126   1,438
                                                               ------- -------
INVESTMENTS...................................................      80     354
                                                               ------- -------
PROPERTY, PLANT AND EQUIPMENT:
 Property, plant and equipment................................   9,336   9,040
 Less accumulated depreciation and amortization...............   4,968   4,813
                                                               ------- -------
   Net property, plant and equipment..........................   4,368   4,227
                                                               ------- -------
DEFERRED CHARGES AND OTHER ASSETS:
 Regulatory assets............................................     196     181
 Prepaid pension cost.........................................     434     255
 Other........................................................     109      80
                                                               ------- -------
   Total deferred charges and other assets....................     739     516
                                                               ------- -------
   Total assets............................................... $ 7,313 $ 6,535
                                                               ======= =======
             LIABILITIES AND STOCKHOLDER'S EQUITY
             ------------------------------------
CURRENT LIABILITIES:
 Short-term debt.............................................. $ 1,215 $   686
 Accounts payable, trade......................................     736     328
 Estimated rate contingencies and refunds.....................      41      45
 Amounts payable to customers.................................     --        4
 Payables to affiliated companies.............................      30     --
 Customer deposits............................................       7       8
 Accrued interest.............................................      24      25
 Accrued payroll..............................................       7       7
 Accrued taxes................................................     178     134
 Deferred income taxes--current (net).........................      86     --
 Dividends declared...........................................     --       46
 Other........................................................     230      70
                                                               ------- -------
   Total current liabilities..................................   2,554   1,353
                                                               ------- -------
LONG-TERM DEBT................................................   1,721   1,764
                                                               ------- -------
DEFERRED CREDITS AND OTHER LIABILITIES:
 Deferred income taxes........................................     788     808
 Deferred investment tax credits..............................      18      20
 Other........................................................     266     214
                                                               ------- -------
   Total deferred credits and other liabilities...............   1,072   1,042
                                                               ------- -------
COMMITMENTS AND CONTINGENCIES


COMMON STOCKHOLDER'S EQUITY:
 Common stock:
   2000--no par, 100 shares authorized, 100 shares issued;
    1999--$2.75 par value, 400,000,000 shares authorized,
    95,948,452 shares issued..................................   1,816     264
 Other capital................................................      40     567
 Retained earnings............................................     110   1,546
 Treasury stock, at cost (1999--10,443 shares)................     --       (1)
                                                               ------- -------
   Total common stockholder's equity..........................   1,966   2,376
                                                               ------- -------
   Total liabilities and stockholder's equity................. $ 7,313 $ 6,535
                                                               ======= =======
</TABLE>
   The accompanying notes are an integral part of the Consolidated Financial
                                  Statements.

                                       35
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

                     CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                                         For The Years Ended
                                                             December 31,
                                                         ----------------------
                                                          2000    1999    1998
                                                         ------  ------  ------
                                                              (Millions)
<S>                                                      <C>     <C>     <C>
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
 Net income............................................  $  244  $  137  $  239
 Adjustments to reconcile net income to net cash from
  operating activities:
 Cumulative effect of a change in accounting
  principle............................................     (31)    --      --
 Loss from discontinued operations.....................     --      --       49
 Restructuring and other merger-related costs..........     143      40     --
 Loss on net assets held for sale......................     152     --      --
 Sale of Virginia Natural Gas..........................    (168)    --      --
 Depreciation and amortization.........................     443     379     330
 Pension cost (credit)--net............................    (149)    (72)    (56)
 Stock award amortization..............................     --        1       7
 Deferred income taxes--net............................      29      47      18
 Investment tax credit.................................      (2)     (2)     (2)
 Changes in current assets and current liabilities:
 Accounts receivable...................................    (400)     (7)      4
 Receivables from affiliated companies.................      26     --      --
 Inventories...........................................     (12)     20      (3)
 Unrecovered gas costs.................................    (225)     (3)     20
 Broker margin deposits................................    (242)    (15)     (7)
 Prepayments...........................................     (28)     10     (14)
 Other current assets..................................     (65)    (35)    (23)
 Accounts payable, trade...............................     336     (52)     93
 Payables to affiliated companies......................     (33)    --      --
 Estimated rate contingencies and refunds..............      (6)    (31)     49
 Amounts payable to customers..........................      (1)    (39)     47
 Accrued expenses......................................      46      16      (2)
 Other-net.............................................      75     (49)      5
 Net assets held for sale..............................       7      (3)    --
 Changes in other assets and liabilities...............     130      26      15
 Other-net.............................................      (1)    --       (2)
                                                         ------  ------  ------
  Net cash flows from continuing operations............     268     368     767
Cash flows from discontinued operations................     --      --       45
                                                         ------  ------  ------
  Net cash flows from operating activities.............     268     368     812
                                                         ------  ------  ------
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
 Plant construction and other property additions:
 Acquisition of exploration and production assets......    (218)   (166)    --
 Other.................................................    (543)   (444)   (562)
 Proceeds from sale of Virginia Natural Gas, net of
  cash sold............................................     532     --      --
 Proceeds from sale of Argentine investments, net of
  cash sold............................................     145     --      --
 Cost of other investments.............................      (7)    (42)   (104)
 Other.................................................       9       7      (1)
                                                         ------  ------  ------
  Net cash flows used in continuing operations.........     (82)   (645)   (667)
 Cash flows from discontinued operations...............     --      --       35
                                                         ------  ------  ------
  Net cash flows used in investing activities..........     (82)   (645)   (632)
                                                         ------  ------  ------
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
 Issuance of common stock..............................     --      --       12
 Issuance of long-term debt............................     --      397     197
 Repayment of long-term debt...........................     (45)   (125)   (327)
 Issuance (repayment) of short-term debt...............     527     126     318
 Dividends paid........................................    (704)   (186)   (186)
 Purchase of treasury stock............................     --      (12)   (281)
 Sale of treasury stock................................     --       33     163
 Other.................................................     --      --       (3)
                                                         ------  ------  ------
  Net cash flows from (used in) financing activities...    (222)    233    (107)
                                                         ------  ------  ------
Increase (decrease) in cash and cash equivalents.......     (36)    (44)     73
Cash and cash equivalents at beginning of the year.....      94     138      65
                                                         ------  ------  ------
Cash and cash equivalents at end of the year...........  $   58  $   94  $  138
                                                         ======  ======  ======
Continuing operations..................................  $   58  $   94  $  135
Discontinued operations................................     --      --        3
                                                         ------  ------  ------
 Total cash and cash equivalents at end of the year....  $   58  $   94  $  138
                                                         ======  ======  ======
</TABLE>

                                       36
<PAGE>

<TABLE>
<CAPTION>
                                                                 For The Years
                                                                     Ended
                                                                 December 31,
                                                               -----------------
                                                               2000  1999  1998
                                                               ----- ----- -----
                                                                  (Millions)
<S>                                                            <C>   <C>   <C>
SUPPLEMENTAL CASH FLOW INFORMATION:
 Cash paid for:
   Interest, excluding capitalized amounts.....................  $ 164 $ 121 $ 122
   Income taxes................................................  $ 103 $  31 $  92
 Non-cash investing activities:
   Investment in partnership...................................  $ --  $   2 $ --
 Non-cash financing activities:
   Conversion of convertible subordinated debentures...........  $ --  $ --  $  88
</TABLE>



   The accompanying notes are an integral part of the Consolidated Financial
                                  Statements.


                                       37
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

                CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

<TABLE>
<CAPTION>
                                                               For The Years
                                                               Ended December
                                                                    31,
                                                               ---------------
                                                               2000  1999 1998
                                                               ----  ---- ----
                                                                 (Millions)
<S>                                                            <C>   <C>  <C>
Net income.................................................... $244  $137 $239
Other comprehensive income, net of tax:
  Foreign currency translation adjustment.....................   (1)    3   (1)
  Less: reclassification adjustment for losses realized in net
   income.....................................................    4   --   --
                                                               ----  ---- ----
  Other comprehensive income (loss)...........................    3     3   (1)
                                                               ----  ---- ----
Comprehensive income.......................................... $247  $140 $238
                                                               ====  ==== ====
</TABLE>



   The accompanying notes are an integral part of the Consolidated Financial
                                  Statements.

                                       38
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Nature of Operations

 General Organization and Legal Description

   Consolidated Natural Gas Company is a public utility holding company
registered under the Public Utility Holding Company Act of 1935. On January 28,
2000, Dominion Resources, Inc. (Dominion) and Consolidated Natural Gas Company
(the Company) completed the merger of the Company into a subsidiary (New
Company) of Dominion. The name of New Company was changed to Consolidated
Natural Gas Company at the time of the merger. To give effect to the continuity
of the Company and New Company, the term "Company" as used in this report
refers to Consolidated Natural Gas Company both before and after the merger
unless the context of a statement requires the use of separate references to
each company.

   The Company, through its subsidiaries, operates in all phases of the natural
gas business, explores for and produces oil and provides a variety of retail
energy marketing services.

   The Company's retail gas distribution subsidiaries include The East Ohio Gas
Company (Dominion East Ohio), The Peoples Natural Gas Company (Dominion
Peoples), Virginia Natural Gas, Inc. (VNG), and Hope Gas, Inc. (Dominion Hope).
These subsidiaries sell gas and/or provide transportation services to
residential, commercial and industrial customers in Ohio, Pennsylvania,
Virginia and West Virginia, and are subject to price regulation by their
respective state utility commissions. See Note 6 for information about the sale
of VNG during 2000.

   Dominion Transmission, Inc. (Dominion Transmission), formerly CNG
Transmission Corporation, operates a regional interstate pipeline system that
provides gas transportation and storage services to each of the Company's
retail gas distribution subsidiaries, and to nonaffiliated pipeline, utility
and end-user customers in the Midwest, the Mid-Atlantic states and the
Northeast.

   Dominion Exploration & Production, Inc. (Dominion E&P), formerly CNG
Producing Company, explores for and produces gas and oil, primarily in the Gulf
of Mexico, the Appalachian region, the southern and western United States and
in Canada. Effective January 1, 2001, Dominion E&P's Canadian properties were
transferred by sale to another subsidiary of Dominion.

   Dominion Field Services, Inc. (Dominion Field Services), formerly CNG Field
Services Company, is engaged in activities related to Appalachian area natural
gas supply. Dominion Retail, Inc. (Dominion Retail), formerly CNG Retail
Services Corporation, pursues opportunities arising from the deregulation of
the energy industry at the retail level. Dominion Products and Services, Inc.
(Dominion Products and Services), formerly CNG Products and Services, Inc.,
provides certain energy-related services to customers of the Company's retail
gas distribution subsidiaries and others.

   CNG International Corporation (CNG International) is engaged in energy-
related activities outside the United States through equity investments.
However, management has committed to a plan of disposal for CNG International.
See Note 7 for information regarding CNG International.

   The Company evaluates its operations along functional lines rather than
legal entities. The principal functional segments include Distribution
(representing the retail gas distribution subsidiaries), Transmission
(representing the pipeline, storage and by-product operations of Dominion
Transmission and the activities of Dominion Field Services), and Exploration
and Production (representing Dominion E&P and the gas and oil production
activities of Dominion Transmission).

                                       39
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

2. Significant Accounting Policies

 General

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

   The consolidated financial statements reflect certain estimates and
assumptions made by management that affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities at the date of
the financial statements, and the reported amounts of revenues and expenses for
the periods presented. Actual results may differ from those estimates.

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

 Revenue

   Revenue is recorded on the basis of services rendered, commodities delivered
or contracts settled and includes amounts yet to be billed to customers.

 Unrecovered Gas Costs

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

 Property, Plant and Equipment

  Utility and Other Plant

   Property, plant and equipment are stated at the cost incurred or, where
required by regulatory authorities, "original cost." Additions and betterments
are charged to the property accounts at cost. Upon normal retirement of a plant
asset, its cost is charged to accumulated depreciation together with costs of
removal less salvage. Maintenance, repairs and related costs are charged
principally to expense as incurred.

  Exploration and Production Properties

   The Company follows the full cost method of accounting for gas and oil
producing activities prescribed by the Securities and Exchange Commission
(SEC). Under the full cost method, all costs directly associated with property
acquisition, exploration, and development activities are capitalized, with the
principal limitation that such amounts not exceed the present value of
estimated future net revenues to be derived from the production of proved gas
and oil reserves (the "ceiling test"). If net capitalized costs exceed the
ceiling test at the end of any quarterly period, then a permanent write-down of
the assets must be recognized in that period. The ceiling test is performed
separately for each cost center, with cost centers established on a country-by-
country basis.


                                       40
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 Depreciation and Amortization

   Depreciation and amortization are recorded over the estimated service lives
of plant assets by application of the straight-line method or, in the case of
gas and oil producing properties, the unit-of-production method.

   Under the full cost method of accounting, amortization is also accrued on
estimated future costs to be incurred in developing proved gas and oil
reserves, and on estimated dismantlement and abandonment costs net of projected
salvage values. However, the costs of investments in unproved properties and
major development projects are excluded from amortization until it is
determined whether or not proved reserves are attributable to such properties.

 Income Taxes

   Subsequent to the January 28, 2000 merger with Dominion, the Company files a
consolidated federal income tax return with Dominion. The Company's current
federal income taxes have been determined pursuant to an intercompany tax
allocation agreement entered into by Dominion and its subsidiaries as required
by the Public Utility Holding Company Act of 1935 (PUHCA).

   Prior to the merger, the Company and its subsidiaries filed a consolidated
federal income tax return. The taxes allocated to the Company and its
subsidiaries were determined pursuant to an intercompany tax allocation
agreement as required by the PUHCA.

   Deferred investment tax credits are being amortized over the estimated
service lives of the related properties.

 Cash and Cash Equivalents

   Current banking arrangements generally do not require checks to be funded
until actually presented for payment. At December 31, 2000 and 1999, accounts
payable included the net effect of checks outstanding but not yet presented for
payment of $77 million and $22 million, respectively.

   For purposes of the Consolidated Statements of Cash Flows, the Company
considers cash and cash equivalents to include cash on hand and temporary
investments purchased with an initial maturity of three months or less.

 Price Risk Management Activities

   In the normal course of business, the Company utilizes derivative financial
instruments and derivative commodity instruments to manage exposure to price
risk in connection with the production, purchase and sale of natural gas and
oil, and for stored gas inventories. These derivatives include exchange-traded
futures and options contracts, which permit settlement by physical delivery of
the commodity, and over-the-counter (OTC) commodity price swap agreements and
options, which require settlement in cash.

   For derivatives that qualify (based on correlation to price movements of gas
and oil) and are designated as hedges, related gains or losses are deferred and
subsequently recognized in income, as revenues or expense, in the same period
the hedged transaction occurs.

   Under the OTC price swap agreements, the Company makes payments to, or
receives payments from, counterparties generally based on the difference
between fixed and variable gas and oil prices or on prices at different receipt
points as specified in the contracts. Settlement takes place under the swap
agreements on a

                                       41
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

monthly basis for the portion of the swap that has expired, and amounts
received or paid are recognized as an adjustment to gas and oil sales revenues,
purchased gas expense or transport capacity costs in the applicable settlement
month.

   Cash flows from price risk management activities are reported in the
Consolidated Statements of Cash Flows as an operating activity, which is
consistent with the classification of the cash flows from the underlying
physical transaction.

 Reclassification

   Certain amounts in the 1999 and 1998 consolidated financial statements have
been reclassified to conform to the 2000 presentation.

3. Change in Accounting

   During the third quarter of 2000, Dominion and its subsidiaries, including
the Company, adopted a company-wide method of calculating the market related
value of pension plan assets used to determine the expected return on pension
plan assets, a component of net periodic pension cost. Under the new method,
the market related value of pension plan assets reflects the difference between
actual investment returns and expected investment returns evenly over a four-
year period. Prior to Dominion's acquisition of the Company, each company used
different methods to determine the "calculated value" of the market related
value of pension plan assets. The method formerly used by the Company
calculated the market related value of pension plan assets as the average of
market values at the end of each of the preceding four years, with appropriate
adjustments for receipts, disbursements, and investment income during the
period. The Company believes that the new method is preferable to continuing to
use either or both of the former methods as the new method enhances the
predictability of expected return on pension plan assets, provides consistent
treatment of all investment gains and losses, and results in calculated market
related pension plan asset values that are closer to market value as compared
to values calculated under the previous methods.

   The $31 million cumulative effect of the change on prior years (net of
income taxes of $11 million) is included in income for the year ended December
31, 2000. The effect of the change on 2000 was to increase income before
cumulative effect of a change in accounting principle by $10 million and net
income by $41 million.

   Had the Company retroactively applied the new method, on a pro forma basis,
net income for the years ended December 31, 1999 and 1998 would have been as
follows:

<TABLE>
<CAPTION>
                                                                    Years Ended
                                                                     December
                                                                        31,
                                                                    -----------
                                                                    1999  1998
                                                                    ----- -----
                                                                    (Millions)
<S>                                                                 <C>   <C>
Net income--as reported............................................ $ 137 $ 239
Net income--pro forma..............................................   144   244
</TABLE>

                                       42
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


4. Recently Issued Accounting Standards

   In June 2000, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 138, Accounting for
Certain Derivative Instruments and Certain Hedging Activities, which amends
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities.
SFAS No. 133 requires that all derivative instruments be recorded on the
Company's balance sheet at their fair value effective January 1, 2001.

   The Company has determined that certain contracts used in its operations
will be subject to fair value accounting under SFAS No. 133. A substantial
portion of these contracts is used by the Company in its production and
delivery of energy to its customers and the contracts involve various hedging
strategies. In addition to these commodity contracts, the Company uses interest
rate swaps to manage its cost of capital.

   Under SFAS No. 133, changes in the fair value of derivatives are recorded
each period in current earnings or other comprehensive income, depending on
whether a derivative is designated and effective as part of a hedge strategy,
and, if it is, whether such strategy represents a fair value or cash flow
hedge. For fair value hedge strategies, where the Company is hedging the
changes in the fair value of assets, liabilities or firm commitments, changes
in the fair value of the derivative instruments will generally be offset in the
income statement by changes in the fair value of the hedged items. For cash
flow hedge strategies, where the Company is hedging the variability of cash
flows related to variable-priced assets, liabilities or forecasted
transactions, including anticipated production, purchases or sales, changes in
the fair value of the derivative instruments will be reported in other
comprehensive income. Amounts recorded in other comprehensive income will be
adjusted for changes in fair value until reclassified to earnings. Such
reclassification will generally occur when earnings are affected by variability
of the cash flows of the hedged transactions in the cash flow hedging strategy
(e.g., anticipated sales). As amounts are reclassified from other comprehensive
income, the impact on earnings should generally be offset by the recognition of
the hedged transactions.

   The Company will record after-tax charges to net income of approximately $14
million and other comprehensive income of approximately $102 million in the
first quarter of 2001 for the initial adoption of SFAS No. 133. These
adjustments will be recognized as of January 1, 2001, as the cumulative effect
of a change in accounting principle.

   The Derivatives Implementation Group (DIG), a group sponsored by the FASB,
continues to develop interpretive guidance. The DIG has not yet resolved
certain issues that could ultimately impact the application of the standard.

5. Merger

   On January 28, 2000, Dominion acquired all of the outstanding shares of the
Company's common stock for $6.4 billion, consisting of approximately 87 million
shares of Dominion common stock valued at $3.5 billion and approximately $2.9
billion in cash. The acquisition was completed by merging the Company into a
new subsidiary of Dominion. The name of the new Dominion subsidiary was changed
to Consolidated Natural Gas Company at the time of the merger.

                                       43
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


6. Restructuring and Other Merger-Related Activities

   Costs recognized by the Company in connection with the merger with Dominion
and the subsequent restructuring of the operations of the combined companies
were as follows:

<TABLE>
<CAPTION>
                                                                       Years
                                                                       Ended
                                                                      December
                                                                        31,
                                                                     ----------
                                                                     2000 1999
                                                                     ---- -----
                                                                     (Millions)
<S>                                                                  <C>  <C>
Commodity contract losses........................................... $ 55 $ --
Settlement of certain employment contracts..........................   47    38
Early retirement program............................................   36   --
Information technology related costs................................   35   --
Severance liability accrued.........................................   31     5
Seismic licensing agreements........................................   26   --
Lease termination and restructuring.................................   11   --
Transaction fees....................................................   10    10
Surrender of vested stock options and awards........................  --    154
Other...............................................................   19     6
                                                                     ---- -----
  Total............................................................. $270 $ 213
                                                                     ==== =====
</TABLE>

 2000 Restructuring and Other Merger-Related Costs

   Dominion and its subsidiaries developed and began the implementation of a
plan to restructure the operations of the combined companies. The restructuring
plan included an involuntary severance program, a voluntary early retirement
program and a transition plan to implement operational changes to provide
efficiencies, including the consolidation of post-merger operations and the
integration of information technology systems.

 Involuntary Severance Program

   Dominion and its subsidiaries established a comprehensive involuntary
severance package for salaried employees impacted by workforce reductions.
Severance payments are based on the individual's base salary and years-of-
service at the time of termination. Under the restructuring plan, a total of
434 positions at the Company and its subsidiaries have been identified for
elimination, resulting in $31 million of severance related costs. At December
31, 2000, a total of 373 positions had been eliminated, and $18 million of
severance benefits had been paid.

 Early Retirement Program

   Salaried employees of the Company and its subsidiaries, excluding officers,
and employees of VNG and CNG International, who had attained age 52 and
completed at least 12 years of service as of July 1, 2000 were eligible under
the early retirement program (ERP). In addition, employees covered by several
collective bargaining agreements were also eligible. The early retirement
option provides up to three additional years of age and three additional years
of employee service for benefit formula purposes, subject to age and service
maximums under the Company's postretirement medical and pension plans. During
the second quarter of 2000, approximately 450 employees elected to participate
in the ERP, resulting in an expense approximating $62 million. This expense was
offset, in part, by curtailment gains of $26 million attributable to reductions
in expected future years of service as a result of ERP participation and
involuntary employee terminations. Some of the ERP participants will also
receive benefits under the involuntary severance package. Benefits under the
involuntary severance package are subject to reduction as a result of
coordination with the additional retirement plan benefits provided by the ERP.

                                       44
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 Other Restructuring and Merger-Related Costs

   During the first quarter of 2000, Dominion implemented a new hedging
strategy for its combined operations. Under its new strategy, Dominion created
an enterprise risk management group with responsibility for managing Dominion's
aggregate energy portfolio, including the related commodity price risk, across
its consolidated operations. Previously, individual business segments managed
their respective energy portfolios and related price risk exposure on a stand-
alone basis. Dominion management believes this new structure should result in
more effective risk management with the objective of maximizing the value of
Dominion's diversified energy portfolio and market opportunities.

   As part of the implementation of the new strategy, management evaluated the
Company's hedging strategy associated with its oil and gas operations in
relation to Dominion's combined operations. As a result of the evaluation, the
Company designated its portfolio of derivative contracts that existed at
January 28, 2000 as held for purposes other than hedging for accounting
purposes. This action required a change to mark-to-market accounting where
derivative contracts are carried at fair value in the balance sheet with any
future unrealized gains and losses included in the determination of net income.
The mark-to-market accounting for these contracts held for purposes other than
hedging resulted in the recognition of losses of $55 million for the first
quarter of 2000 and the year ended December 31, 2000. In addition, the Company
entered into offsetting contracts for those contracts in the January 28, 2000
portfolio that would not be settled during the first quarter of 2000. Due to
these offsetting contracts, absent any not yet identified future losses from
credit risk exposure, no additional material losses are expected to be realized
as these derivative contracts mature through 2003. See Note 20 for further
discussion.

   The change of control required settlement of certain employment contracts
and payments under seismic licensing agreements used in the Company's oil and
gas operations. The information technology related costs include excess
amortization expense attributable to shortening the useful lives of capitalized
software being impacted by systems integration, and related conversion costs.
The lease termination and restructuring costs are being incurred as operations
are streamlined and work locations are consolidated.

 Sale of Virginia Natural Gas

   On October 6, 2000, the Company completed the sale of VNG to AGL Resources
Inc. Cash proceeds from the sale amounted to $533 million. The Company was
required to spin-off or sell VNG pursuant to conditions set forth by the
Virginia State Corporation Commission and Federal Trade Commission in
connection with their approval of the acquisition of the Company by Dominion.

   In connection with the sale of VNG, the Company transferred the pension and
postretirement medical benefit liabilities relating to VNG's employees to AGL,
together with the related plan assets. As a result, the Company recognized
curtailment and settlement gains of $26 million. The total gain recognized on
the sale of VNG, including the curtailment and settlement gains, amounted to
$163 million ($98 million after taxes).

 1999 Restructuring and Other Merger-Related Costs

   Shareholder approval of the merger with Dominion constituted a change of
control as defined in the Company's then effective stock incentive plans. The
change of control triggered acceleration of the vesting of stock options and
certain other stock awards. Also, the change of control effectively granted
limited stock appreciation rights to holders of vested stock options and
certain other stock awards. Holders were permitted to elect to receive a cash
payment in exchange for surrendering vested stock options and awards during the
period July 1, 1999 through August 29, 1999. The amount to be paid to the
holders was based on the value determined

                                       45
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

per the associated plans, which considered the option exercise price, award
value, and the change of control price as defined in the plans. Based on the
value of the vested options and awards expected to be surrendered and cashed
out, the Company recognized a charge of $154 million during the second quarter
of 1999.

   During 1999, the Company also recorded charges for the costs related to
certain executive employment agreements and for other merger-related costs,
including direct incremental costs (including fees of financial advisors, legal
counsel and other costs).

7. Impairment of International Investments

   CNG International has been engaged in energy-related activities outside of
the United States, primarily through equity investments in Australia and
Argentina. Consistent with its strategy to focus on its core business, in the
first quarter of 2000 management committed to a plan of disposal for CNG
International. The total loss related to CNG International, discussed below,
was $152 million ($99 million after tax) for the year ended December 31, 2000.

 Argentine Investments

   On July 7, 2000, Sempra Energy International, a subsidiary of Sempra Energy,
agreed to purchase CNG International's Argentine assets for $145 million. Based
upon anticipated proceeds from the sale, the carrying amount of these
investments was adjusted and an impairment loss of $17 million, $11 million
after-tax, was recognized in the second quarter of 2000. On October 12, 2000,
CNG International completed the sale of its Argentine assets to Sempra Energy
International for $145 million in cash.

 Australian Investments

   In March 1998, CNG International purchased a 33.3% ownership interest in the
Dampier-to-Bunbury Natural Gas Pipeline (DBNGP) in Western Australia from the
Western Australian Government. One of CNG International's partners in the
purchase was El Paso Energy Corporation (El Paso), which also holds a 33.3%
ownership interest. In connection with their investments in DBNGP, CNG
International and El Paso formed DBNGP Finance Company LLC (DBNGP Finance).
DBNGP Finance is owned 50% by CNG International and 50% by EPED Holding
Company, a wholly-owned subsidiary of El Paso. Subsequent to the formation of
DBNGP Finance, the equity ownership interests of CNG International and El Paso
in DBNGP were transferred to this entity.

   In October 1998, DBNGP Finance borrowed $250 million under a Senior Term
Loan Facility (Term Loan). The Term Loan matures October 2, 2001, can be
extended in one-year increments to October 2, 2003, and bears interest at a
variable rate. Of the gross proceeds received by DBNGP Finance under the Term
Loan, $100 million was distributed to CNG International. In connection with the
Term Loan, CNG International entered into an Equity Contribution Agreement with
DBNGP Finance. CNG International is contractually obligated to make equity
contributions to DBNGP Finance equal to the Term Loan proceeds distributed to
CNG International, plus interest on such proceeds, in the event that DBNGP
Finance is unable to service this debt. The Company is contractually obligated
to cause CNG International to make such equity contributions.

   In connection with the Company's decision to end its involvement with
international activities, the Company recognized a pretax loss of $35 million
($23 million after taxes) to write down the carrying amount of CNG
International's Australian investments to estimated fair value less cost to
sell. The Company's estimate was based principally on a discounted cash flow
analysis. In addition, the Company believes it is probable that, as part of a
sale, it will be required to make a $100 million equity contribution pursuant
to the Equity

                                       46
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

Contribution Agreement discussed above. Accordingly, the Company recognized a
$100 million ($65 million after taxes) charge in the year ended December 31,
2000. During the second quarter of 2000, the Company became aware of certain
information that existed in the first quarter of 2000. However, the evaluation
of such data was not completed until sometime thereafter. Management,
therefore, determined that recognition of the impairment and accrual for the
probable equity contribution would most appropriately be reflected in the first
quarter of 2000. As a result, the Company restated the March 31, 2000 carrying
value of CNG International's Australian investments and retroactively
recognized a loss of $135 million ($88 million after taxes) in the first
quarter of 2000. On August 24, 2000, the Company filed a Form 10-Q/A for the
quarterly period ended March 31, 2000 to reflect this information.

8. Discontinued Operations

   During April 1998, management approved a plan to discontinue the Company's
wholesale trading and marketing of natural gas and electricity, including
integrated energy management. On July 31, 1998, the sale of the capital stock
of CNG Energy Services Corporation, formerly a wholly-owned subsidiary of the
Company, to Sempra Energy Trading, a subsidiary of Sempra Energy, was
finalized. Proceeds of $37 million were received from the sale of the stock, as
adjusted for working capital items. The Company's transition out of the
wholesale gas and electricity business was substantially complete at December
31, 1998. The remaining net liabilities associated with discontinued operations
at December 31, 1999 were not material.

   The results of operations of these activities for the year ended December
31, 1998 are classified as "Discontinued Operations" in the Consolidated
Statements of Income. Cash flows in connection with operating and investing
activities for discontinued operations are reported separately in the
Consolidated Statements of Cash Flows. There were no cash flows provided by, or
used in, financing activities related to discontinued operations.

   Summarized results of operations of the discontinued operations are as
follows:

<TABLE>
<CAPTION>
                                                                     Year Ended
                                                                    December 31,
                                                                        1998
                                                                    ------------
                                                                     (Millions)
<S>                                                                 <C>
Total operating revenues...........................................    $ 793
Operating expenses.................................................     (818)
                                                                       -----
  Operating loss before income taxes...............................      (25)
Income tax benefit.................................................        9
Interest charges...................................................       (1)
                                                                       -----
  Loss from discontinued operations................................    $ (17)
                                                                       =====
Loss from disposal before income taxes.............................    $ (49)
Income tax benefit.................................................       17
                                                                       -----
  Net loss from disposal...........................................    $ (32)
                                                                       =====
</TABLE>

9. Workforce Reduction Costs

   During the fourth quarter of 1998, the Company recorded a provision for
severance and other employee-related costs in connection with programs to
improve efficiencies and reorganize business processes at both its corporate
and regulated subsidiaries. Certain severance benefits were enhanced under
these programs and such programs were completed during 1999. During 1999, a
total of 241 employees were separated from the Company in conjunction with
these workforce reduction programs.

                                       47
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   As a result of its workforce reduction programs, the Company recorded
charges in 1999 and 1998 amounting to $11 million and $9 million, respectively.
These charges reduced 1999 and 1998 net income by $7 million and $6 million,
respectively. In addition, certain of the regulated subsidiaries have deferred,
as a regulatory asset, a portion of workforce reduction costs from previous
years' programs pending recovery in rates. The balance of these deferrals was
$8 million at December 31, 2000.

10. Income Taxes

   Details of income tax expense are as follows:

<TABLE>
<CAPTION>
                                                               Years Ended
                                                               December 31,
                                                              ----------------
                                                              2000  1999  1998
                                                              ----  ----  ----
                                                                (Millions)
<S>                                                           <C>   <C>   <C>
Income tax expense attributable to continuing operations:
  Current expense:
    Federal.................................................. $108  $23   $ 96
    State....................................................   12    5     18
  Deferred expense (benefit):
    Federal..................................................   22   44     21
    State....................................................    7    3     (3)
  Deferred investment tax credits--amortization..............   (2)  (2)    (2)
                                                              ----  ---   ----
Income tax expense attributable to continuing operations.....  147   73    130
Income tax benefit attributable to discontinued operations...  --   --     (26)
                                                              ----  ---   ----
  Total...................................................... $147  $73   $104
                                                              ====  ===   ====
</TABLE>

   Total income tax expense differs from the amount computed by applying the
statutory federal income tax rate to pretax income from continuing operations
for the following reasons:

<TABLE>
<CAPTION>
                                                               Years Ended
                                                               December 31,
                                                              ----------------
                                                              2000  1999  1998
                                                              ----  ----  ----
                                                                (Millions)
<S>                                                           <C>   <C>   <C>
Income from continuing operations before income taxes........ $360  $210  $418
                                                              ====  ====  ====
Federal income tax expense at federal statutory rate......... $126  $ 74  $146
Increases (reductions) resulting from:
  Production tax credit......................................  (10)  (11)  (11)
  SFAS No. 71 flow through items:
    Pension..................................................   (8)   (6)   (6)
    Gain (loss) on sale of assets............................    7   --     (1)
  Amortization of investment tax credits.....................   (2)   (2)   (2)
  State income taxes, net of federal tax benefit.............   12     5     9
  Non-deductible change of control payments..................    8     5   --
  Prior year tax adjustments.................................    9     3     2
  CNG International equity earnings..........................  --      4   --
  Miscellaneous..............................................    5     1    (7)
                                                              ----  ----  ----
  Total income tax expense attributable to continuing
   operations................................................ $147  $ 73  $130
                                                              ====  ====  ====
  Effective tax rate......................................... 40.8% 35.0% 31.1%
</TABLE>

                                       48
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   The Company's net deferred income taxes consist of the following:

<TABLE>
<CAPTION>
                                                       December 31,
                                            -----------------------------------
                                                  2000              1999
                                            ----------------- -----------------
                                                     Deferred          Deferred
                                            Deferred  Income  Deferred  Income
                                             Income   Taxes-   Income   Taxes-
                                             Taxes   Current   Taxes   Current
                                            -------- -------- -------- --------
                                                        (Millions)
<S>                                         <C>      <C>      <C>      <C>
Deferred income tax liabilities:
  Excess of tax over book depreciation.....  $  599    $--      $561     $--
  Exploration and intangible well drilling
   costs...................................     237     --       243      --
  Unrecovered gas costs....................     --      102      --        11
  Net pension credits......................     177     --       101      --
  Equity earnings..........................      18     --        11      --
  Other....................................       2     --         1      --
                                             ------    ----     ----     ----
    Total liabilities......................   1,033     102      917       11
                                             ------    ----     ----     ----
Deferred income tax assets:
  Gas storage inventory encroachment and
   other...................................      86     --        30      --
  Impairment of international investments..      47     --       --       --
  Uncollectible accounts...................      23     --         6      --
  Deferred and other compensation..........      13     --        11      --
  Overheads capitalized for tax purposes...      12     --        11      --
  Deferred investment tax credits..........      10     --        12      --
  Other postretirement benefits............       9     --         8      --
  Excise tax...............................       8     --       --       --
  Supplier and other refunds...............     --       16      --        12
  AMT carryforward.........................     --      --        14      --
  Other....................................      37     --        17      --
  Valuation allowance......................     --      --       --       --
                                             ------    ----     ----     ----
    Total assets...........................     245      16      109       12
                                             ------    ----     ----     ----
    Total deferred income tax liability
     (asset)...............................  $  788    $ 86     $808     $ (1)
                                             ======    ====     ====     ====
</TABLE>

   A regulatory liability amounting to $18 million has been recorded at
December 31, 2000 representing the reduction to previously recorded deferred
income taxes associated with rate-regulated activities that are expected to be
refundable to customers, net of certain taxes collectible from customers. Also,
at December 31, 2000, a regulatory asset in the amount of $128 million has been
recorded corresponding to additional deferred income taxes not recognized due
to rate-making practices.

                                       49
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


11. Regulatory Assets and Liabilities

   The Company accounts for its regulated operations in accordance with SFAS
No. 71, Accounting for the Effects of Certain Types of Regulation. When the
accounting allocations prescribed by regulatory authorities are used for
ratemaking, the allocation of costs among accounting periods by the Company's
regulated subsidiaries resulted in the recognition of regulatory assets and
liabilities at December 31, 2000 and 1999 as follows:

<TABLE>
<CAPTION>
                                                                     December
                                                                        31,
                                                                    -----------
                                                                    2000  1999
                                                                    ----- -----
                                                                    (Millions)
<S>                                                                 <C>   <C>
Regulatory assets:
  Unrecovered gas costs (Note 2)................................... $ 264 $  38
  Workforce reduction costs (Note 9)...............................     8     8
  Other postretirement benefits (Note 18)..........................    40    43
  Income taxes recoverable through future rates (Note 10)..........   128   115
  Environmental-related expenditures (Note 19).....................     4     5
  Other............................................................    16    10
                                                                    ----- -----
    Total regulatory assets........................................ $ 460 $ 219
                                                                    ===== =====
Regulatory liabilities:
  Amounts payable to customers (Note 2)............................ $ --  $   4
  Estimated rate contingencies and refunds.........................    41    45
  Income taxes refundable to customers-net (Note 10)...............    18    22
                                                                    ----- -----
    Total regulatory liabilities................................... $  59 $  71
                                                                    ===== =====
</TABLE>

   The regulatory assets shown above represent amounts currently being
recovered in rates or amounts deferred pending recovery in future rates.
Recovery periods range from one month in the case of unrecovered gas costs
being recovered in current rates, to up to 40 years for income taxes related to
plant assets. While regulatory assets are recovered through rates charged
customers, substantially all of these amounts are not included in rate base for
rate-making purposes and, therefore, are not earning a return.

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

 Estimated Rate Contingencies and Refunds

   Certain increases in prices by the Company and other rate-making issues are
subject to final modification in regulatory proceedings. The related
accumulated provisions pertaining to these matters were $40 million and $39
million at December 31, 2000 and 1999, including interest. These amounts are
reported in the Consolidated Balance Sheets under "Estimated rate contingencies
and refunds" together with $1 million and $6 million, respectively, which are
primarily refunds received from suppliers and refundable to customers under
regulatory procedures.

12. Gas Stored

   The distribution subsidiaries value their stored gas inventory under the
LIFO method. Based upon the average price of gas purchased during 2000, the
current cost of replacing the inventory of "Gas stored--current portion"
exceeded the amount stated on a LIFO basis by approximately $283 million at
December 31, 2000. The other subsidiaries value their stored gas inventory
under the weighted average cost method.

                                       50
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   A portion of gas in underground storage used as a pressure base and for
operational balancing is included in "Property, Plant and Equipment" in the
amount of $126 million at December 31, 2000 and 1999.

13. Property, Plant and Equipment and Depreciation

 Property, Plant and Equipment

   Property, plant and equipment consists of the following:

<TABLE>
<CAPTION>
                                                                  December 31,
                                                                  -------------
                                                                   2000   1999
                                                                  ------ ------
                                                                   (Millions)
<S>                                                               <C>    <C>
Utility:
  Transmission................................................... $1,528 $1,546
  Distribution...................................................  1,694  1,631
  Storage........................................................    573    666
  Other..........................................................    630    656
  Construction work in progress..................................     41     66
                                                                  ------ ------
      Total utility..............................................  4,466  4,565
                                                                  ------ ------
Nonutility:
  Exploration and production:
    Proved.......................................................  3,909  3,735
    Unproved.....................................................    705    480
  Other..........................................................    256    260
                                                                  ------ ------
      Total nonutility...........................................  4,870  4,475
                                                                  ------ ------
      Total property, plant and equipment........................ $9,336 $9,040
                                                                  ====== ======
</TABLE>

 Depreciation and Amortization

   Amortization of capitalized costs under the full cost method of accounting
for the Company's United States and Canadian cost centers were as follows:

<TABLE>
<CAPTION>
                                                                 Years Ended
                                                                December 31,
                                                              -----------------
                                                              2000  1999  1998
                                                              ----- ----- -----
                                                                  (Per Mcf
                                                                 Equivalent)
<S>                                                           <C>   <C>   <C>
United States cost center.................................... $1.31 $1.14 $1.07
Canadian cost center.........................................   .17   .12   .09
</TABLE>

   Costs of unproved properties capitalized under the full cost method of
accounting that are excluded from amortization at December 31, 2000, and the
years in which such excluded costs were incurred, follow:

<TABLE>
<CAPTION>
                                                             Incurred in Years
                                                             Ended December 31,
                                               December 31, --------------------
                                                   2000     2000 1999 1998 Prior
                                               ------------ ---- ---- ---- -----
                                                          (Millions)
<S>                                            <C>          <C>  <C>  <C>  <C>
Property acquisition costs....................     $ 70     $29  $14  $11   $16
Exploration costs.............................       76      46   11   10     9
Capitalized interest..........................       14       2    2    4     6
                                                   ----     ---  ---  ---   ---
  Total.......................................     $160     $77  $27  $25   $31
                                                   ====     ===  ===  ===   ===
</TABLE>

                                       51
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   There are no significant properties, as defined by the SEC, excluded from
amortization at December 31, 2000. As gas and oil reserves are proved through
drilling or as properties are judged to be impaired, excluded costs and any
related reserves are transferred on an ongoing, well-by-well basis into the
amortization calculation.

14. Short-Term Debt and Credit Agreements

   The weighted average interest rate on the Company's commercial paper notes
outstanding at December 31, 2000 and 1999, was 7.05% and 6.45%, respectively.

   In June 2000, Dominion established a $1.75 billion credit facility that
supports the combined commercial paper programs of the Company, Virginia
Electric and Power Company (another Dominion subsidiary), and Dominion.
Although the Company has access to the full $1.75 billion facility, it operates
with an internal allocation that may vary depending upon the needs of
participating entities.

15. Long-Term Debt

   Long-term debt, excluding current maturities, follows:

<TABLE>
<CAPTION>
                                                                 December 31,
                                                                 --------------
                                                                  2000    1999
                                                                 ------  ------
                                                                  (Millions)
<S>                                                              <C>     <C>
Notes(/1/):
  7 1/4%, Due October 1, 2004(/2/).............................. $  400  $  400
Debentures(/1/):
  6%, Due October 15, 2010(/2/).................................    200     200
  6.8%, Due December 15, 2027(/3/)..............................    300     300
  6 5/8%, Due December 1, 2008(/2/).............................    150     150
  6 7/8%, Due October 15, 2026(/4/).............................    150     150
  7 3/8%, Due April 1, 2005(/2/)................................    150     150
  6 5/8%, Due December 1, 2013(/2/).............................    150     150
  5 3/4%, Due August 1, 2003(/2/)...............................    150     150
  8 3/4%, Due October 1, 2019(/5/)..............................     84     129
  Unamortized debt discount, less premium.......................    (13)    (15)
                                                                 ------  ------
    Total....................................................... $1,721  $1,764
                                                                 ======  ======
</TABLE>
--------
(1) The Notes and Debentures are unsecured obligations and rank on a parity
    with all other unsecured and unsubordinated debt of the Company.
(2) Not redeemable prior to maturity and not subject to any sinking fund.
(3) Not subject to any sinking fund. Redeemable as a whole or in part, at the
    option of the Company, at any time.
(4) Not redeemable prior to maturity. The debentures will be purchased by the
    Company at the option of the holder on October 15, 2006, at 100% of the
    principal amount, plus accrued interest.
(5) Subject to an annual sinking fund of $7,125,000 through 2018, with
    $7,500,000 due at maturity. The Company may, at its option, redeem for the
    sinking fund at 100% of the principal amount, up to an additional
    $14,250,000 at any sinking fund date. Redeemable as a whole or in part, at
    the option of the Company, at any time for 103.04% of the principal amount
    in 2001, declining to 100% in 2009 and thereafter.

                                       52
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   Discounts and premiums and the expenses incurred in connection with the
issuance of long-term debt are being amortized on a basis which will equitably
distribute the amount to "Interest on long-term debt" over the life of each
issue.

   There is no long-term debt maturing in the years 2001 and 2002. The
aggregate principal amounts of the Company's long-term debt maturing in the
years 2003 through 2005 are: $150 million; $400 million and $150 million.

16. Common Stockholder's Equity

   A summary of the changes in stockholder's equity follows:

<TABLE>
<CAPTION>
                             Common Stock
                                Issued           Other Capital                            Treasury Stock
                          ------------------  -------------------                        ----------------
                            Number                                                         Number
                           of Shares                               Retained   Unearned    of Shares
                          (Thousands) Value   Paid-in Other Total  Earnings Compensation (Thousands) Cost
                          ----------- ------  ------- ----- -----  -------- ------------ ----------- ----
                                                  (Millions, except share data)
<S>                       <C>         <C>     <C>     <C>   <C>    <C>      <C>          <C>         <C>
Balance at December 31,
 1997...................     95,623   $  263   $527    $40  $567    $1,540      $(11)          (1)   $--
Net income..............        --       --     --     --    --        239       --           --      --
Cash dividends
 declared--common
 stock..................        --       --     --     --    --       (186)      --           --      --
Common stock issued
 Stock options and
 awards.................        322        1     13    --     13       --         (2)         --      --
 Amortization and
  adjustment............        --       --      (2)   --     (2)      --         11          --      --
Purchase of treasury
 stock..................        --       --     --     --    --        --        --        (5,081)   (280)
Sale of treasury stock..        --       --      (4)   --     (4)      --        --         2,949     163
Conversion of
 debentures.............        --       --      (2)   --     (2)      --        --         1,638      91
Foreign currency
 translation
 adjustment.............        --       --     --     --    --         (1)      --           --      --
                            -------   ------   ----    ---  ----    ------      ----       ------    ----
Balance at December 31,
 1998...................     95,945      264    532     40   572     1,592        (2)        (495)    (26)
Net income..............        --       --     --     --    --        137       --           --      --
Cash dividends
 declared--common
 stock..................        --       --     --     --    --       (186)      --           --      --
Common stock issued
 Stock options and
 awards.................          3      --     --     --    --        --        --           --      --
 Amortization...........        --       --     --     --    --        --          2          --      --
Purchase of treasury
 stock..................        --       --     --     --    --        --        --          (225)    (13)
Sale of treasury stock..        --       --      (5)   --     (5)      --        --           710      38
Foreign currency
 translation
 adjustment.............        --       --     --     --    --          3       --           --      --
                            -------   ------   ----    ---  ----    ------      ----       ------    ----
Balance at December 31,
 1999...................     95,948      264    527     40   567     1,546       --           (10)     (1)
Net income--January 1 to
 January 27.............        --       --     --     --    --         87       --           --      --
Retirement of treasury
 stock..................        (10)     --      (1)   --     (1)      --        --            10       1
Merger with Dominion....    (95,938)   2,163   (526)   --   (526)   (1,637)      --           --      --
Net income--January 28
 to December 31.........        --       --     --     --    --        157       --           --      --
Cash dividends
 declared--common
 stock..................        --      (611)   --     --    --        (46)      --           --      --
Foreign currency
 translation
 adjustment.............        --       --     --     --    --          3       --           --      --
                            -------   ------   ----    ---  ----    ------      ----       ------    ----
Balance at December 31,
 2000...................        --*   $1,816   $--     $40  $ 40    $  110      $--           --     $--
                            =======   ======   ====    ===  ====    ======      ====       ======    ====
</TABLE>
--------
*  Following the merger with Dominion, 100 shares of common stock, no par
   value, were issued and outstanding.

 Treasury Stock

   Prior to the merger with Dominion, the Company was authorized by the Board
of Directors to purchase in the open market up to 10,000,000 shares of its
common stock. The Company could also acquire shares of its common stock through
certain provisions of the Company's various stock incentive plans. Shares
repurchased or acquired were held as treasury stock and were available for
reissuance for general corporate purposes or in

                                       53
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

connection with various employee benefit plans. When treasury shares were
reissued, the difference between the market value at reissuance and the cost of
shares was reflected in "Other capital--paid in." At December 31, 1999, 10,443
shares were being held as treasury stock. Immediately prior to the merger with
Dominion, all treasury stock held by the Company was retired.

 1997 Stock Incentive Plan

   The 1997 Stock Incentive Plan (1997 Plan) provided for the granting of stock
awards, stock options and other stock-based awards to employees and directors
of the Company effective January 1, 1997, including grants made on or after
that date pursuant to the Long-Term Strategic Incentive Program described
below. The maximum number of shares authorized for issuance in each calendar
year was determined in accordance with a formula contained in the 1997 Plan. As
of January 28, 2000, no further grants were made under the 1997 Plan or the
Long-Term Strategic Incentive Plan due to the Company's merger with Dominion.

   Stock awards granted under the plan may have been in the form of restricted
stock or deferred stock. Shares issued as restricted stock awards were held by
the Company until the attached restrictions lapsed. Deferred stock awards
generally consisted of a right to receive shares at the end of specified
deferral periods. The market value of the stock award on the date granted was
recorded as compensation expense over the applicable restriction or deferral
period.

   Stock options granted under the plan allowed the purchase of common shares
at a price not less than fair market value at the date of grant and not less
than par value. These options, other than tri-annual options granted under the
Long-Term Strategic Incentive Program, generally were exercisable in four equal
annual installments commencing with the second anniversary of the grant and
expired after 10 years from the date of grant.

   The granting of stock awards constituted a non-cash financing activity of
the Company.

 Long-Term Strategic Incentive Program

   Grants under the Long-Term Strategic Incentive Program consisted of
performance restricted stock awards (performance shares or performance stock
credits) and stock options. Grants were made under this program in January 1996
and January 1999.

   Performance shares vested contingent upon attainment of certain strategic
business results over a three-year period. The market value of the performance
shares on the grant date, as adjusted quarterly for changes in the current
market price of the Company's common stock, was recorded as compensation
expense over the three-year vesting period.

   Stock options granted under this program (tri-annual options) vested after
three years and would be exercisable from the vesting date until ten years from
the grant date if certain strategic business results were attained during the
vesting period. However, the exercise period would be reduced to one day for
all or a portion of the options granted if such results were not achieved. As
the number of options were known and the option price equaled the market price
at the grant date, no compensation expense was recognized for these options
under generally accepted accounting principles.

   There were no grants outstanding under this program at December 31, 1999.

                                       54
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 Accounting for Stock Awards and Stock Options

   As permitted by generally accepted accounting principles, the Company
follows Accounting Principles Board Opinion No. 25 and related interpretations
(APB No. 25) for accounting for stock-based compensation. The Company granted
stock awards, including performance shares, totaling 459,000 shares in 1999 and
54,000 shares in 1998 with weighted average market prices per share on award
dates of $53.91 and $49.54, respectively. The Company recorded compensation
expense of $159 million for the year ended December 31, 1999 in connection with
its performance shares, restricted stock and other stock compensation awards,
and stock options that were surrendered and cashed out in connection with
shareholder approval of the Company's then pending merger with Dominion. The
Company recorded compensation expense of $9 million for the year ended December
31, 1998 in connection with its performance shares, restricted stock and other
stock compensation awards.

   In accordance with APB No. 25, no compensation expense has been recognized
for the Company's stock options, other than for those surrendered and cashed
out in connection with shareholder approval of the Company's merger with
Dominion.

   A summary of stock option activity for the years ended December 31, 1998
through 2000, follows:

<TABLE>
<CAPTION>
                                                                       Weighted
                                                                        Average
                                                                        Option
                                                            Number of    Price
                                                             Shares    Per Share
                                                           ----------- ---------
                                                           (Thousands)
<S>                                                        <C>         <C>
Shares under option:
  At December 31, 1997....................................    5,207     $45.73
  Granted(1)..............................................      914     $58.34
  Exercised...............................................     (309)    $41.73
  Cancelled(1)............................................     (307)    $51.32
                                                             ------
  At December 31, 1998....................................    5,505     $47.73
  Granted(2)..............................................    3,800     $53.79
  Exercised...............................................     (700)    $46.55
  Cancelled(2)............................................   (2,266)    $53.51
  Surrendered.............................................   (6,337)    $49.44
                                                             ------
  At December 31, 1999....................................        2     $55.47
  Surrendered.............................................       (2)    $55.47
                                                             ------
  At December 31, 2000....................................      --
                                                             ======
</TABLE>
--------
(1) Includes 106,750 tri-annual options granted and 96,114 tri-annual options
    cancelled.
(2) Includes 3,002,917 tri-annual options granted and 1,968,211 tri-annual
    options cancelled.

   Options were exercisable for the purchase of 2,000 shares and 734,741 shares
at December 31, 1999 and 1998, respectively.

                                       55
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 Fair Value Disclosures

   The following table presents the weighted-average fair value of stock
options granted during 1998 and the weighted-average assumptions used to
compute fair values under the Black-Scholes option-pricing model:

<TABLE>
<CAPTION>
                                                                     Year Ended
                                                                    December 31,
                                                                        1998
                                                                    ------------
<S>                                                                 <C>
Option fair value..................................................    $10.49
Assumptions:
  Dividend yield...................................................       3.3%
  Expected volatility..............................................      19.8%
  Risk-free interest rate..........................................       5.7%
  Expected option life (years).....................................       4.8
</TABLE>

   If compensation expense for the Company's stock options granted during 1998
had been determined based on the fair value at the grant dates for such awards,
the Company's net income would have been $232 million, compared to the $239
million reported in that year.

   Reference is made to Note 6 regarding the surrender and cash out of stock
options between July 1, 1999 and August 29, 1999 in connection with shareholder
approval of the Company's then pending merger with Dominion.

17. Dividend Restrictions

   One of the Company's indentures relating to its long-term debt contains
restrictions on dividend payments by the Company and acquisitions of its
capital stock. Under the indenture provisions, $19 million of consolidated
retained earnings was free from such restrictions at December 31, 2000. The
indenture also imposes dividend limitations on the subsidiaries, but at
December 31, 2000, these limitations did not restrict their ability to pay
dividends to the Company.

18. Pension and Other Postretirement Benefit Costs

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

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

                                       56
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   Following the January 28, 2000 merger, Dominion and its subsidiaries,
including the Company, offered an early retirement program (ERP) as part of a
plan to restructure the operations of the combined companies. The ERP provided
up to three additional years of age and three additional years of employee
service for benefit formula purposes, subject to age and service maximums under
the Company's postretirement medical and pension plans. Certain employees who
satisfied certain minimum age and years of service requirements were eligible
under the ERP. The effect of the ERP on the Company's pension plan and
postretirement benefit expenses was $42 million and $20 million, respectively.
These expenses were offset, in part, by curtailment gains of approximately $19
million and $7 million from pension plans and other postretirement benefit
plans, respectively, attributable to reductions in expected future years of
service as a result of ERP participation and involuntary employee terminations.

   In connection with the sale of VNG, the Company transferred the pension and
postretirement medical benefit liabilities relating to VNG's employees to AGL
Resources Inc., together with the related plan assets. As a result, the Company
recognized curtailment and settlement gains of $26 million.

   In addition, effective January 1, 2000, Dominion and its subsidiaries,
including the Company, adopted a change in the method of calculating the
market-related value of pension plan assets. The cumulative effect of this
change on prior years is reported as a change in accounting principle. See Note
3.

                                       57
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   The following tables provide reconciliations of the changes in the Company's
pension and other postretirement benefit plan obligations and asset fair values
for each of the years ended December 31, 2000 and 1999, and a statement of the
funded status as of December 31, 2000 and 1999:

<TABLE>
<CAPTION>
                                                Years Ended December 31,
                                              --------------------------------
                                                                   Other
                                                 Pension      Postretirement
                                              Benefit Plans    Benefit Plans
                                              --------------  ----------------
                                               2000    1999    2000     1999
                                              ------  ------  -------  -------
                                                       (Millions)
<S>                                           <C>     <C>     <C>      <C>
Change in benefit obligation:
Benefit obligation--January 1................ $  970  $1,124  $   297  $   362
Service cost.................................     21      29       11       10
Interest cost................................     72      71       24       20
Participant contributions....................    --      --       --         3
Plan amendments..............................    --      --        (6)     --
Actuarial (gain) loss........................     33    (186)      64      (75)
Change of control benefits...................     11     --       --       --
Special termination benefits.................     42     --        20      --
Curtailment..................................    (19)    --        (6)     --
Sale of Virginia Natural Gas.................    (45)    --       (20)     --
Benefit payments.............................    (79)    (68)     (21)     (23)
                                              ------  ------  -------  -------
Benefit obligation--December 31.............. $1,006  $  970  $   363  $   297
                                              ======  ======  =======  =======
Change in plan assets:
Fair value of plan assets--January 1......... $2,326  $2,069  $   128  $   112
Actual return on plan assets.................     69     322       10        1
Employer contributions.......................      7       3       35       35
Participant contributions....................    --      --       --         3
Sale of Virginia Natural Gas.................    (37)    --       (12)     --
Benefit payments.............................    (79)    (68)     (19)     (23)
                                              ------  ------  -------  -------
Fair value of plan assets--December 31....... $2,286  $2,326  $   142  $   128
                                              ======  ======  =======  =======
Funded status:
Funded status--December 31................... $1,280  $1,356  $  (221) $  (169)
Unrecognized net obligation (asset)..........    (18)    (25)     129      147
Unrecognized (gain) loss-net.................   (859) (1,119)       5      (58)
Unrecognized prior service cost..............      3       4      (10)      (5)
                                              ------  ------  -------  -------
Net amount recognized........................ $  406  $  216  $   (97) $   (85)
                                              ======  ======  =======  =======
</TABLE>

   Amounts recognized in the Consolidated Balance Sheets at December 31 consist
of the following:

<TABLE>
<S>                                                   <C>   <C>   <C>    <C>
Prepaid benefit cost................................. $434  $235  $ --   $ --
Accrued benefit liability............................  (34)  (28)   (97)   (85)
Intangible asset.....................................    4     7    --     --
Accumulated other comprehensive income...............    2     2    --     --
                                                      ----  ----  -----  -----
Net amount recognized................................ $406  $216  $ (97) $ (85)
                                                      ====  ====  =====  =====
</TABLE>

                                       58
<PAGE>

                       CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   The Company has nonqualified pension and supplemental pension plans which
do not have "plan assets" as defined by generally accepted accounting
principles. The total projected benefit obligation for these plans was $31
million and $30 million at December 31, 2000 and 1999, respectively, and is
included in the table above. The minimum liability recognized relating to
these plans was $6 million and $9 million at December 31, 2000 and 1999. The
related intangible asset recognized as of those dates amounted to $4 million
and $7 million, respectively. Adjustments of the minimum liability and
intangible asset due to changes in assumptions or the financial status of
these plans resulted in a charge or credit to other comprehensive income of
less than $1 million for each of the years ended December 31, 2000, 1999 and
1998.

   The majority of estimated other postretirement benefit costs (SFAS No. 106
costs) and related transition obligation is attributable to the rate-regulated
subsidiaries. Pending the expected recovery of SFAS No. 106 costs and related
deferrals in regulatory proceedings, these subsidiaries have deferred the
differences between SFAS No. 106 costs and amounts included in rates. The
rate-regulated subsidiaries have obtained approval for recovery in rates from
their respective regulatory commissions for the increased level of expense
resulting from SFAS No. 106. The amount of SFAS No. 106 costs deferred at
December 31, 2000 and 1999, was $40 million and $43 million, respectively.

   The FERC and certain state regulatory authorities have indicated that when
SFAS No. 106 costs are recovered in rates, amounts collected must be deposited
in irrevocable trust funds dedicated for the sole purpose of paying
postretirement benefits. Accordingly, certain subsidiaries fund postretirement
benefit costs through voluntary employees' beneficiary associations (VEBAs).
The remaining subsidiaries do not prefund postretirement benefit costs, but
rather pay claims as presented. Assets held by the VEBAs consist primarily of
short-term fixed income securities.

   Weighted average assumptions used in the determination of the benefit
obligations include the following:

<TABLE>
<CAPTION>
                                                                  Other
                                              Pension        Postretirement
                                           Benefit Plans      Benefit Plans
                                           ---------------   -----------------
                                            2000     1999     2000      1999
                                           ------   ------   -------   -------
<S>                                        <C>      <C>      <C>       <C>
Discount rate.............................    7.5%     7.5%      7.5%      7.5%
Expected return on plan assets............    9.5%     9.0%      6.5%      6.5%
Rate of compensation increase
  Non-union...............................    5.0%     5.0%      5.0%      5.0%
  Union...................................    4.0%     4.0%      4.0%      4.0%
</TABLE>

                                      59
<PAGE>

                       CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   Net periodic benefit costs, as determined by independent actuaries,
included the following components:

<TABLE>
<CAPTION>
                                         Years Ended December 31,
                                   -------------------------------------------
                                       Pension        Other Postretirement
                                    Benefit Plans        Benefit Plans
                                   -----------------  ------------------------
                                   2000   1999  1998   2000     1999     1998
                                   -----  ----  ----  ------   ------   ------
                                                (Millions)
<S>                                <C>    <C>   <C>   <C>      <C>      <C>
Service cost.....................  $  21  $ 29  $ 25  $   11   $   10   $   10
Interest cost....................     72    71    69      24       20       24
Expected return on assets........   (193) (151) (132)     (7)      (6)      (5)
Prior service cost amortization..      1   --      1     --       --       --
Actuarial (gain) loss............    (44)  (14)  (11)    --        (1)     --
Transition obligation
 amortization....................     (8)   (8)   (7)     11       11       11
Special termination benefits.....     42   --    --       20      --       --
Curtailment (gain) loss..........    (19)  --     (2)     (7)     --       --
Curtailment and settlement gain--
 Sale of Virginia Natural Gas....    (26)  --    --      --       --       --
Special voluntary retirement
 programs........................      1     1     1     --       --       --
                                   -----  ----  ----  ------   ------   ------
Net periodic benefit cost
 (credit)........................  $(153) $(72) $(56) $   52   $   34   $   40
                                   =====  ====  ====  ======   ======   ======
</TABLE>

   For measurement purposes, a 9.0% annual rate of increase in the per capita
cost of covered health care benefits was assumed for 2000. The rate was
assumed to decrease to 4.75% by 2005 and remain at that level thereafter.

   Assumed health care cost trend rates have a significant effect on the
amounts reported for the postretirement health care plans. A 1% change in the
assumed health care cost trend rate would have the following effects on 2000
service and interest cost and the accumulated postretirement benefit
obligation at December 31, 2000:

<TABLE>
<CAPTION>
                                                                1%       1%
                                                             Increase Decrease
                                                             -------- --------
                                                                (Millions)
<S>                                                          <C>      <C>
Effect on aggregate service and interest cost components of
 net periodic cost..........................................   $ 4      $ (3)
Effect on the health care component of the accumulated
 postretirement benefit obligation..........................   $32      $(27)
</TABLE>

19. Commitments and Contingencies

   Lease arrangements of the Company are principally for office space,
business machines and transportation equipment. None of these arrangements,
individually or in the aggregate, are material capital leases. Rental expense
incurred in the years 1998 through 2000 was not material, and future rental
payments required under leases in effect at December 31, 2000, are not
material.

   It is estimated that the Company's 2001 capital spending program will
amount to $813 million, and that approximately $587 million of that amount
will be directed to gas and oil producing activities. In connection with the
capital spending program, the Company has entered into certain contractual
commitments.

   The Company has claims and suits arising in the ordinary course of business
pending against it, but, in the opinion of management and counsel, the
ultimate liability will not have a material effect on its financial position,
results of operations or cash flows.

                                      60
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 Environmental Matters

   The Company is subject to various federal, state and local laws and
regulations relating to the protection of the environment. These laws and
regulations govern both current and future operations and potentially extend to
plant sites formerly owned or operated by the subsidiaries, or their
predecessors.

   The Company has taken a proactive position with respect to environmental
concerns. As part of normal business operations, subsidiaries periodically
monitor their properties and facilities to identify and resolve potential
environmental matters, and the Company conducts general environmental audits on
a continuing basis at its operating facilities to monitor compliance with
environmental laws and regulations. As part of this process, voluntary surveys
at subsidiary sites have been conducted to determine the extent of any possible
soil contamination and when contamination has been discovered remediation
efforts are undertaken. Further, on August 16, 1990, Dominion Transmission
entered into a Consent Order and Agreement with the Commonwealth of
Pennsylvania Department of Environmental Protection (DEP) in which Dominion
Transmission has agreed with the DEP's determination of certain violations of
the Pennsylvania Solid Waste Management Act, the Pennsylvania Clean Streams Law
and the rules and regulations promulgated thereunder. No civil penalties have
been assessed. Pursuant to the Order and Agreement, Dominion Transmission
continues to perform sampling, testing and analysis, and conducts remediation
at some of its affected Pennsylvania facilities. Total remediation costs in
connection with these sites and the Order and Agreement are not expected to be
material with respect to the Company's financial position, results of
operations or cash flows. The Company has recognized an estimated liability
amounting to $6 million at December 31, 2000, for future costs expected to be
incurred to remediate or mitigate hazardous substances at these sites and at
facilities covered by the Order and Agreement.

   Inasmuch as certain environmental-related expenditures are expected to be
recoverable in future regulatory proceedings, a regulatory asset has been
recognized amounting to $4 million at December 31, 2000. Also, uncontested
claims amounting to $2 million at December 31, 2000, were recognized for
environmental-related costs probable for recovery through joint-interest
operating agreements.

   The total amounts included in operating expenses for remediation and other
environmental-related costs were $4 million in 2000, $5 million in 1999 and $6
million in 1998.

   Dominion Transmission and certain of the distribution subsidiaries are
subject to the Federal Clean Air Act (Clean Air Act) and the Federal Clean Air
Act Amendments of 1990 (1990 amendments) which added significantly to the
existing Clean Air Act requirements. As a result of the 1990 amendments, these
subsidiaries were required to acquire Title V permits for major facilities.
Progress is on schedule for these permits, with no major expenditures
anticipated. The 1990 amendments will also require installation of Maximum
Available Control Technology (MACT) to control the emissions of certain
hazardous air pollutants from compressor engines. The Company cannot estimate
what its expenditures for MACT-related controls will be. However, the mandated
controls will not affect a large number of its compressor engines and the
related costs are not expected to be material.

   Additionally, the Company may be required, under an Environmental Protection
Agency nitrogen oxide state implementation program call, to include additional
compressor engines in the control mandates for the 1990 Amendments. The
estimated costs of such federal and/or state imposed hardware additions are not
expected to be material.

   The total capital expenditures required to comply with the 1990 amendments
are expected to be recoverable through future regulatory proceedings.

                                       61
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   The Company has determined that it is associated with 16 former manufactured
gas plant sites, four of which are currently owned by subsidiaries. Studies
conducted by other utilities at their former manufactured gas plants have
indicated that their sites contain coal tar and other potentially harmful
materials. None of the 16 former sites with which the Company is associated is
under investigation by any state or federal environmental agency, and no
investigation or action is currently anticipated. At this time it is not known
if, or to what degree, these sites may contain environmental contamination.
Therefore, the Company is not able to estimate the cost, if any, that may be
required for the possible remediation of these sites.

   During 2000, Dominion Transmission paid a total of $380,000 related to a
hydrocarbon spill in February 1998 at one of its facilities in Aliquippa,
Beaver County, Pennsylvania. Dominion settled the matter by contributing
$200,000 to the Penn's Corner Conservancy Charitable Trust and $80,000 to the
Beaver County Conservation District, and paying $100,000 to the DEP for
response costs.

   Estimates of liability in the environmental area are based on current
environmental laws and existing technology. The exact nature of environmental
issues which the Company may encounter in the future cannot be predicted.
Additional environmental liabilities may result in the future as more stringent
environmental laws and regulations are implemented and as the Company obtains
more specific information about its existing sites and production facilities.
At present, no estimate of any such additional liability, or range of liability
amounts, can be made. However, the amount of any such liabilities could be
material.

20. Financial Instruments

 Fair Values

   The Company used available market information and appropriate valuation
methodologies to estimate the fair value of each class of financial instrument
for which it is practicable to estimate fair value. These estimates are not
necessarily indicative of the amounts the Company could realize in a market
exchange. In addition, the use of different market assumptions may have a
material effect on the estimated fair value amounts.

<TABLE>
<CAPTION>
                                                       December 31,
                                            ------------------------------------
                                                 2000               1999
                                            ---------------  -------------------
                                            Carrying  Fair   Carrying
                                             Amount  Value    Amount  Fair Value
                                            -------- ------  -------- ----------
                                                        (Millions)
<S>                                         <C>      <C>     <C>      <C>
Assets:
  Cash and cash equivalents................  $   58  $   58   $   94    $   94
Liabilities:
  Short-term debt..........................   1,215   1,215      686       686
  Long-term debt...........................   1,734   1,689    1,779     1,664
Unrecognized financial instruments:
  Interest rate swap agreement.............     --       18      --        --
  Swaps, collars and options--hedging......     --     (182)     --        (40)
</TABLE>

   Cash and cash equivalents: The carrying amount of cash and cash equivalents
approximates fair value because of their short maturity.

   Short-term debt: The carrying amount of short-term debt approximates fair
value because of its short maturities.

   Long-term debt: Market values are used to determine the fair value for debt
securities for which a market exists. For debt issues that are not quoted on an
exchange, interest rates currently available to the Company for issuance of
debt with similar terms and remaining maturities are used to estimate fair
value.

                                       62
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   Interest rate swap agreement: Fair value was determined by the counterparty
to the agreement and is based upon the present value of all estimated net
future cash flows. A negative value indicates that the valuation results in a
projected net payment by the Company.

   Swaps, collars and options-hedging: Fair value reflects the Company's best
estimates considering over-the-counter quotations, time value and volatility
factors of the underlying commitments.

 Derivatives and Price Risk Management Activities

   During the first quarter of 2000, Dominion implemented a new hedging
strategy for its combined operations. Under its new strategy, Dominion created
an enterprise risk management group with responsibility for managing Dominion's
aggregate energy portfolio, including the related commodity price risk, across
its consolidated operations. Previously, individual business segments managed
their respective energy portfolios and related price risk exposure on a stand-
alone basis. Dominion management believes this new structure should result in
more effective risk management with the objective of maximizing the value of
Dominion's diversified energy portfolio and market opportunities.

   As part of the implementation of the new strategy, management evaluated the
Company's hedging strategy associated with its oil and gas operations in
relation to Dominion's combined operations. As a result of the evaluation, the
Company designated its portfolio of derivative contracts that existed at
January 28, 2000 as held for purposes other than hedging for accounting
purposes. This action required a change to mark-to-market accounting where
derivative contracts are carried at fair value in the balance sheet with any
future unrealized gains and losses included in the determination of net income.
At January 28, 2000, the fair value of the derivative contracts represented a
net unrealized loss of approximately $70 million. This net unrealized loss will
be included in the determination of net income, as an adjustment to revenues,
through net settlement accounting as such contracts mature through 2003. At
December 31, 2000, approximately $22 million of the $70 million of net
unrealized losses are included in Deferred Charges and Other Assets, pending
future settlement of the related contracts.

   In addition, during the first quarter of 2000, the Company entered into
offsetting contracts for those contracts in the January 28, 2000 portfolio that
were not settled during the first quarter of 2000. Up to the date that the
offsetting contracts were entered into, the mark-to-market accounting for the
original portfolio resulted in a loss of approximately $55 million for the
first quarter of 2000 and year ended December 31, 2000. Due to the Company's
establishing the offsetting portfolio of derivative contracts, absent any not
yet identified future losses from credit risk exposure, no additional material
losses are expected to be realized as these derivative contracts mature through
2003. Related to these contracts, a liability representing future contract
settlements of approximately $40 million is reported in Deferred Credits and
Other Liabilities at December 31, 2000.

   Pursuant to the implementation of Dominion's new risk management strategy,
the Company and its subsidiaries entered into new derivative contracts and
designated them as hedges of sales of future oil and gas production. Any losses
ultimately realized on the hedging portfolio should generally be offset by
future sales revenue from oil and gas production.

 Commodity-based Instruments--Non-Trading

   The Company manages the price risk associated with purchases and sales of
natural gas and oil by selecting derivative commodity instruments whose
historical price fluctuations correlate strongly with those of the transaction
being hedged. These commodity-based financial derivatives include swaps,
options and collars which require settlement in cash. As these instruments
qualify and have been designated as hedges, any gains or losses resulting from
market price changes are expected to be generally offset by the related
physical transaction.

                                       63
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   At December 31, 2000, the Company held swaps with notional quantities of
approximately 339 Bcf of natural gas maturing through 2001-2005 with an
aggregate unrealized gain of $198 million. Net notional quantities do not
represent the quantities exchanged by the parties and are not a measure of the
Company's exposure through the use of swaps, but are used in the determination
of cash settlements under the swap agreements.

   At December 31, 2000, the Company held options and collars covering
approximately 186 Bcf of natural gas and 5 million barrels of crude oil
maturing through 2001-2003 with an aggregate unrealized loss of $380 million.

   At December 31, 1999, the Company held swaps, options and collars covering
approximately 383 Bcf of natural gas and 5 million barrels of oil maturing
through 2000-2003 with an aggregate unrealized loss of $40 million.

 Interest Rate Contracts

   During 2000, the Company entered into an interest rate swap agreement in
order to manage exposure to the effects of interest rate changes on outstanding
debt. The net notional amount does not represent the amounts exchanged by the
parties, and is not a measure of the Company's exposure through the use of the
swap, but is used in the determination of cash settlements under the agreement.
At December 31, 2000, the swap synthetically converted $400 million of fixed-
rate debt to variable-rate debt.

 Risk Management Policies

   The Company has operating procedures in place that are administered by
experienced management to help ensure that proper internal controls regarding
the use of derivatives are maintained. In addition, Dominion has established an
independent function to monitor compliance with the price risk management
policies of all subsidiaries. Dominion maintains credit policies with respect
to its counterparties that management believes minimize overall credit risk.
Such policies include the evaluation of a prospective counterparty's financial
condition, collateral requirements where deemed necessary and the use of
standardized agreements which facilitate the netting of cash flows associated
with a single counterparty. Dominion also monitors the financial condition of
existing counterparties on an ongoing basis. Considering the system of internal
controls in place and credit reserve levels at December 31, 2000, management
believes it unlikely that a material adverse effect on its financial position,
results of operations or cash flows would occur as a result of counterparty
nonperformance.

   In addition to the financial derivatives disclosed above, the Company held
futures contracts that may be settled through the purchase or delivery of
commodities. As of December 31, 2000, these instruments were not considered
financial derivatives. However, on January 1, 2001, the Company adopted SFAS
No. 133, which changed the scope and method of accounting for derivatives. See
Note 4 for a discussion of the impact of adoption of this standard.

21. Related Party Transactions

   Subsequent to the January 28, 2000 merger with Dominion, the Company engaged
in the exchange of certain quantities of natural gas (at index prices) and
electricity (at market prices) with affiliates in the ordinary course of
business. During the period from January 28, 2000 through December 31, 2000,
the Company sold $61 million of natural gas and $1 million of electricity to
affiliated companies, and purchased $25 million of natural gas and $5 million
of electricity from affiliates. In addition, the Company provided gas
transportation, storage and other services to affiliates for a consideration of
$7 million.

                                       64
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   Effective February 1, 2000, Dominion created a subsidiary service company,
Dominion Resources Services, Inc. (Dominion Services), which provides certain
administrative and technical services to the Company for which costs are
allocated to the Company in accordance with a formal service contract as
required under the PUHCA. The cost of services provided by Dominion Services
during the period February 1, 2000 through December 31, 2000, amounted to $30
million. At December 31, 2000, the Company had receivables from affiliated
companies of $20 million, and payables to affiliates of $30 million. Balances
due from or payable to affiliates are settled based on contractual terms or on
a monthly basis, depending on the nature of the underlying transactions. See
Note 2 for a discussion of the inclusion of the Company in Dominion's
consolidated federal income tax return.

22. Business Segments

   The Company is organized primarily on the basis of products and services
sold in the United States.

   The operations of the retail gas distribution subsidiaries have been
aggregated into the Distribution segment. These subsidiaries sell gas and/or
provide transportation services to residential, commercial and industrial
customers in Ohio, Pennsylvania and West Virginia, and are subject to price
regulation by their respective state utility commissions. The Distribution
segment also includes the results of VNG prior to its sale to AGL Resources
Inc. VNG provided gas sales and transportation services to customers in
Virginia, and is subject to price regulation by the Virginia State Corporation
Commission (Virginia Commission). The sale of VNG, effective September 30,
2000, was made pursuant to conditions set forth by the Virginia Commission and
the Federal Trade Commission in connection with their approval of the
acquisition of the Company by Dominion.

   Transmission operations include the activities of Dominion Transmission,
Dominion Field Services, and the gas by-products business of CNG Power.
Dominion Transmission, an interstate pipeline company regulated by the FERC,
provides gas transportation, storage and related services to affiliates and to
utilities and end users in the Midwest, the Mid-Atlantic states and the
Northeast. Dominion Transmission also holds a 16% partnership interest in the
Iroquois Gas Transmission System, L.P., a limited partnership that owns and
operates an interstate natural gas pipeline that transports Canadian gas to
utility and power generation customers in New York and New England. Dominion
Field Services is engaged in activities related to Appalachian area natural gas
supply and provides natural gas storage facilities and services and other
activities of a full service gas storage business. Prior to 2000, the results
of Dominion Field Services were included in Other. As a result of the change,
segment information for the years 1999 and 1998 has been restated. Although the
Transmission segment includes the gas by-products business of CNG Power, this
subsidiary effectively exited that business during 2000.

   Exploration and Production includes the results of Dominion Exploration &
Production and the gas and oil production activities of Dominion Transmission.
These operations are located throughout the United States and in the Gulf of
Mexico and Canada. However, Dominion Exploration & Production's Canadian
properties were transferred by sale to another subsidiary of Dominion effective
January 1, 2001. Also included in this segment are CNG Main Pass Gas Gathering
and CNG Oil Gathering. These two subsidiaries hold equity investments in gas
and oil gathering systems located in the Gulf of Mexico.

   The activities of Dominion Retail, Dominion Products and Services, CNG
International and other minor subsidiaries are included in the Other segment.
Dominion Retail pursues opportunities arising from the deregulation of the
energy industry at the retail level. Dominion Products and Services provides
certain energy-related services to customers of the Company's distribution
subsidiaries and others. CNG International engages in energy-related activities
outside of the United States and at December 31, 2000, held equity investments
in

                                       65
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

Australia and Latin America. Consistent with its strategy to focus on its core
business, in the first quarter of 2000 management committed to a plan of
disposal for CNG International. As part of this effort, in October 2000, CNG
International completed the sale of its Argentine assets to Sempra Energy
International.

   The accounting policies of the segments are the same as those described in
the "Summary of Significant Accounting Policies." Transactions between
affiliates are recognized at prices which approximate market value. Significant
transactions between the operating components are eliminated to reconcile the
segment information to consolidated amounts.

   The following table presents segment information pertaining to the Company's
operations:

<TABLE>
<CAPTION>
                                          Year Ended December 31, 2000
                         ----------------------------------------------------------------
                                                   Exploration         Corporate
                                                       and                and
                         Distribution Transmission Production  Other  Eliminations Total
                         ------------ ------------ ----------- -----  ------------ ------
                                                   (Millions)
<S>                      <C>          <C>          <C>         <C>    <C>          <C>
Operating revenue and
 income:
 Nonaffiliated
  Regulated gas sales...    $1,719       $  --       $  --     $--       $ --      $1,719
  Nonregulated gas
   sales................       --           514         --      107        --         621
  Gas transportation and
   storage..............       222          322           1     --         --         545
  Gas and oil
   production...........       --           --          525     --         --         525
  Other revenue.........        37           78         382      35          1        533
                            ------       ------      ------    ----      -----     ------
    Total
     nonaffiliated......     1,978          914         908     142          1      3,943
 Affiliated.............         4          221         108      44       (308)        69
                            ------       ------      ------    ----      -----     ------
    Total operating
     revenue and
     income.............     1,982        1,135       1,016     186       (307)     4,012
Interest income.........       --             3           7       3         (4)         9
Interest charges........        58           30          45       3         26        162
Income (loss) from
 operations.............       264          235         267      (6)      (283)       477
Depreciation and
 amortization...........        85           59         289       2          8        443
Unusual items:
 Restructuring and other
  merger-related costs..       --           --          --      --         270        270
 Loss on net assets held
  for sale..............       --           --          --      --         152        152
 Gain on sale of
  Virginia Natural Gas..       --           --          --      --         163        163
Equity in earnings of
 equity investees.......       --             7           4       6        --          17
Income tax expense
 (benefit)..............        71           81          74     --         (79)       147
Income (loss) from
 continuing operations
 before cumulative
 effect of a change in
 accounting principle...       144          134         154      (2)      (217)       213
Other significant non-
 cash items:
 Pension cost (credit)..       (98)         (38)         (5)     (1)        (7)      (149)
Investment in equity
 investees..............       --            29          49      67        --         145
Total assets............     3,078        1,778       2,289     309       (141)     7,313
Capital expenditures....       126           69         607       9          2        813
</TABLE>

                                       66
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

<TABLE>
<CAPTION>
                                          Year Ended December 31, 1999
                         ----------------------------------------------------------------
                                                   Exploration         Corporate
                                                       and                and
                         Distribution Transmission Production  Other  Eliminations Total
                         ------------ ------------ ----------- -----  ------------ ------
                                                   (Millions)
<S>                      <C>          <C>          <C>         <C>    <C>          <C>
Operating revenue and
 income:
 Nonaffiliated
  Regulated gas sales...    $1,397       $  --       $  --     $--       $ --      $1,397
  Nonregulated gas
   sales................       --           109         --      102        --         211
  Gas transportation and
   storage..............       209          357           1     --         --         567
  Gas and oil
   production...........       --           --          369     --         --         369
  Other revenue.........        29           50         323      28        --         430
                            ------       ------      ------    ----      -----     ------
    Total
     nonaffiliated......     1,635          516         693     130        --       2,974
 Affiliated.............         5          138          60       1       (204)       --
                            ------       ------      ------    ----      -----     ------
    Total operating
     revenue and
     income.............     1,640          654         753     131       (204)     2,974
Interest income.........       --             3           1       1         (3)         2
Interest charges........        48           24          30       3         19        124
Income (loss) from
 operations.............       203          209         135      (6)      (221)       320
Depreciation and
 amortization...........        80           55         236       2          6        379
Unusual items:
 Restructuring and other
  merger-related costs..       --           --          --      --         213        213
Equity in earnings of
 equity investees.......       --             6           6      11        --          23
Income tax expense
 (benefit)..............        48           72          29       3        (79)        73
Income (loss) from
 continuing operations
 before cumulative
 effect of a change in
 accounting principle...       101          121          83      (4)      (164)       137
Other significant non-
 cash items:
 Pension cost (credit)..       (54)         (21)          2       1        --         (72)
Investment in equity
 investees..............       --            38          51     260        --         349
Total assets............     2,874        1,518       1,767     317         59      6,535
Capital expenditures....       111           49         435      38          4        637
</TABLE>

                                       67
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


<TABLE>
<CAPTION>
                                          Year Ended December 31, 1998
                         ----------------------------------------------------------------
                                                   Exploration         Corporate
                                                       and                and
                         Distribution Transmission Production  Other  Eliminations Total
                         ------------ ------------ ----------- -----  ------------ ------
                                                   (Millions)
<S>                      <C>          <C>          <C>         <C>    <C>          <C>
Operating revenue and
 income:
 Nonaffiliated
  Regulated gas sales...    $1,373       $  --       $  --     $  1      $ --      $1,374
  Nonregulated gas
   sales................       --            46         --       79        --         125
  Gas transportation and
   storage..............       198          347           1     --         --         546
  Gas and oil
   production...........       --           --          340     --         --         340
  Other revenue.........        35           55         197      13          5        305
                            ------       ------      ------    ----      -----     ------
    Total
     nonaffiliated......     1,606          448         538      93          5      2,690
 Affiliated.............         6          102          23      12       (143)       --
                            ------       ------      ------    ----      -----     ------
    Total operating
     revenue and
     income.............     1,612          550         561     105       (138)     2,690
Interest income.........         1            5           1       2         (5)         4
Interest charges........        47           25          22       8         12        114
Income (loss) from
 operations.............       208          192         117     (10)       (10)       497
Depreciation and
 amortization...........        75           57         186       7          5        330
Equity in earnings of
 equity investees.......       --             8           5      12        --          25
Income tax expense
 (benefit)..............        59           64          23      (4)       (12)       130
Income (loss) from
 continuing operations
 before cumulative
 effect of a change in
 accounting principle...       110          117          78       2        (19)       288
Other significant non-
 cash items:
 Pension cost (credit)..       (42)         (16)          2     --         --         (56)
Investment in equity
 investees..............       --            37          48     210        --         295
Total assets............     2,947        1,592       1,524     308         (9)     6,362
Capital expenditures....       146           57         353     193         12        761
</TABLE>

                                       68
<PAGE>

                       CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


23. Gas and Oil Producing Activities (Unaudited)

 Capitalized Costs

   The aggregate amounts of costs capitalized for gas and oil producing
activities, and related aggregate amounts of accumulated depreciation and
amortization, follow:

<TABLE>
<CAPTION>
                                                                   December 31,
                                                                   -------------
                                                                    2000   1999
                                                                   ------ ------
                                                                    (Millions)
<S>                                                                <C>    <C>
Capitalized costs of
  Proved properties............................................... $3,909 $3,735
  Unproved properties.............................................    705    480
                                                                   ------ ------
    Subtotal......................................................  4,614  4,215
                                                                   ------ ------
Accumulated depreciation of
  Proved properties...............................................  2,612  2,556
  Unproved properties.............................................    253    182
                                                                   ------ ------
    Subtotal......................................................  2,865  2,738
                                                                   ------ ------
    Net capitalized costs......................................... $1,749 $1,477
                                                                   ====== ======
</TABLE>

 Total Costs Incurred

   The following costs were incurred in gas and oil producing activities
during the years 1998 through 2000:

<TABLE>
<CAPTION>
                                          Years Ended December 31,
                         -----------------------------------------------------------
                                2000                1999                1998
                         ------------------- ------------------- -------------------
                               United              United              United
                         Total States Canada Total States Canada Total States Canada
                         ----- ------ ------ ----- ------ ------ ----- ------ ------
                                                 (Millions)
<S>                      <C>   <C>    <C>    <C>   <C>    <C>    <C>   <C>    <C>
Property acquisition
 costs
  Proved properties..... $215   $215  $ --   $171   $171  $ --   $ 21   $ 21  $ --
  Unproved properties...   39     39    --     33     33    --     29     29    --
                         ----   ----  -----  ----   ----  -----  ----   ----  -----
    Subtotal............  254    254    --    204    204    --     50     50    --
Exploration costs.......  113    113    --    113    113    --    116    116    --
Development costs.......  192    189      3    95     94      1   176    176    --
                         ----   ----  -----  ----   ----  -----  ----   ----  -----
    Total............... $559   $556  $   3  $412   $411  $   1  $342   $342  $ --
                         ====   ====  =====  ====   ====  =====  ====   ====  =====
</TABLE>

                                      69
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 Results of Operations

   The Company cautions that the following standardized disclosures required by
the FASB do not represent the results of operations based on its historical
financial statements. In addition to requiring different determinations of
revenue and costs, the disclosures exclude the impact of interest expense and
corporate overheads.

<TABLE>
<CAPTION>
                                          Years Ended December 31,
                         -----------------------------------------------------------
                                2000                1999                1998
                         ------------------- ------------------- -------------------
                               United              United              United
                         Total States Canada Total States Canada Total States Canada
                         ----- ------ ------ ----- ------ ------ ----- ------ ------
                                                 (Millions)
<S>                      <C>   <C>    <C>    <C>   <C>    <C>    <C>   <C>    <C>
Revenue (net of
 royalties) from:
 Sales to nonaffiliated
  companies............. $551   $545   $  6  $382   $377   $ 5   $358   $355  $   3
 Transfers to other
  operations............   98     98    --     52     52   --      25     25    --
                         ----   ----   ----  ----   ----   ---   ----   ----  -----
   Total................  649    643      6   434    429     5    383    380      3
                         ----   ----   ----  ----   ----   ---   ----   ----  -----
Less: Production
 (lifting) costs........   93     90      3    81     78     3     63     60      3
  Depreciation and
   amortization.........  276    276    --    224    224   --     177    177    --
  Income tax expense....   93     92      1    38     37     1     41     41    --
                         ----   ----   ----  ----   ----   ---   ----   ----  -----
Results of operations... $187   $185   $  2  $ 91   $ 90   $ 1   $102   $102  $ --
                         ====   ====   ====  ====   ====   ===   ====   ====  =====
</TABLE>

 Company-Owned Reserves

   Estimated net quantities of proved gas and oil (including condensate)
reserves in the United States and Canada at December 31, 1998 through 2000, and
changes in the reserves during those years, are shown in the two schedules
which follow. The gas and oil reserve volumes previously reported for 1999 and
1998 have been restated from a "net before royalty" basis to a "net revenue"
basis to conform to Dominion's presentation. This change also conforms the
Company's presentation to that widely used by the industry.

<TABLE>
<CAPTION>
                                          Years Ended December 31,
                         -----------------------------------------------------------------
                                2000                  1999*                 1998*
                         --------------------- --------------------- ---------------------
                                United                United                United
                         Total  States  Canada Total  States  Canada Total  States  Canada
                         -----  ------  ------ -----  ------  ------ -----  ------  ------
                                                    (Bcf)
<S>                      <C>    <C>     <C>    <C>    <C>     <C>    <C>    <C>     <C>
Proved developed and
 undeveloped reserves--
 Gas
At January 1............ 1,205  1,204      1   1,110  1,109      1     965    964      1
Changes in reserves
 Extensions, discoveries
  and other additions...   142    142    --      113    113    --      181    181    --
 Revisions of previous
  estimates.............   (71)   (71)   --      (61)   (61)   --       60     60    --
 Production.............  (173)  (173)   --     (153)  (153)   --     (133)  (133)   --
 Purchases of gas in
  place**...............   129    129    --      206    206    --       37     37    --
 Sales of gas in place..    (8)    (8)   --      (10)   (10)   --      --     --     --
                         -----  -----    ---   -----  -----    ---   -----  -----    ---
At December 31.......... 1,224  1,223      1   1,205  1,204      1   1,110  1,109      1
                         =====  =====    ===   =====  =====    ===   =====  =====    ===

Proved developed
 reserves--Gas
At January 1............   960    959      1     895    894      1     788    787      1
At December 31..........   974    973      1     960    959      1     895    894      1
</TABLE>
--------
*  Restated from a "net before royalty" basis to a "net revenue" basis.
** Amount for 1998 includes 34 Bcf of reserves transferred by sale to Dominion
   Exploration & Production from an affiliate, Dominion Peoples.

                                       70
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

<TABLE>
<CAPTION>
                                            Years ended December 31,
                         ----------------------------------------------------------------------
                                 2000                   1999*                   1998*
                         ----------------------  ----------------------  ----------------------
                                 United                  United                  United
                         Total   States  Canada  Total   States  Canada  Total   States  Canada
                         ------  ------  ------  ------  ------  ------  ------  ------  ------
                                                (Thousand Bbls)
<S>                      <C>     <C>     <C>     <C>     <C>     <C>     <C>     <C>     <C>
Proved developed and
 undeveloped reserves--
 Oil
At January 1............ 49,287  42,643  6,644   46,625  41,854  4,771   41,386  36,106  5,280
Changes in reserves
 Extensions, discoveries
  and other additions... 12,814  12,814    --     6,209   6,034    175    9,198   9,198    --
 Revisions of previous
  estimates............. (2,028) (2,318)   290    5,352   3,325  2,027    2,420   2,421     (1)
 Production............. (7,213) (6,861)  (352)  (8,545) (8,216)  (329)  (6,468) (5,960)  (508)
 Purchases of oil in
  place.................  6,293   6,293    --       806     806    --        89      89    --
 Sales of oil in place.. (1,880) (1,880)   --    (1,160) (1,160)   --       --      --     --
                         ------  ------  -----   ------  ------  -----   ------  ------  -----
At December 31.......... 57,273  50,691  6,582   49,287  42,643  6,644   46,625  41,854  4,771
                         ======  ======  =====   ======  ======  =====   ======  ======  =====

Proved developed
 reserves--Oil
At January 1............ 38,934  32,290  6,644   34,960  30,189  4,771   30,795  25,515  5,280
At December 31.......... 27,910  21,328  6,582   38,934  32,290  6,644   34,960  30,189  4,771
</TABLE>
--------
*Restated from a "net before royalty" basis to a "net revenue" basis.

 Standardized Measure of Discounted Future Net Cash Flows and Changes Therein

   The following tabulation has been prepared in accordance with the FASB's
rules for disclosure of a standardized measure of discounted future net cash
flows relating to Company-owned proved gas and oil reserve quantities.

<TABLE>
<CAPTION>
                                              Years Ended December 31,
                          ----------------------------------------------------------------
                                   2000                  1999                 1998
                          ---------------------- -------------------- --------------------
                                  United                United               United
                           Total  States  Canada Total  States Canada Total  States Canada
                          ------- ------- ------ ------ ------ ------ ------ ------ ------
                                                     (Millions)
<S>                       <C>     <C>     <C>    <C>    <C>    <C>    <C>    <C>    <C>
Future cash inflows.....  $12,914 $12,842  $72   $3,996 $3,878  $118  $2,563 $2,532  $31
Less: Future development
   and production
   costs................    1,152   1,102   50      907    845    62     756    732   24
  Future income tax
   expense..............    4,072   4,068    4      934    918    16     483    484   (1)
                          ------- -------  ---   ------ ------  ----  ------ ------  ---
Future net cash flows...    7,690   7,672   18    2,155  2,115    40   1,324  1,316    8
Less annual discount
 (10% a year)...........    3,164   3,158    6      802    788    14     436    433    3
                          ------- -------  ---   ------ ------  ----  ------ ------  ---
Standardized measure of
 discounted future net
 cash flows.............  $ 4,526 $ 4,514  $12   $1,353 $1,327  $ 26  $  888 $  883  $ 5
                          ======= =======  ===   ====== ======  ====  ====== ======  ===
</TABLE>

   In the foregoing determination of future cash inflows, sales prices for gas
were based on contractual arrangements or market prices at each year-end.
Prices for oil were based on average prices received from sales in the month of
December each year. Future cash inflows also reflect the effects of hedging
activities. Future costs of developing and producing the proved gas and oil
reserves reported at the end of each year shown were based on costs determined
at each such year end, assuming the continuation of existing economic
conditions. Future income taxes were computed by applying the appropriate year-
end or future statutory tax rate to future pretax net cash flows, less the tax
basis of the properties involved, and giving effect to tax deductions, or
permanent differences and tax credits.

                                       71
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   It is not intended that the FASB's standardized measure of discounted future
net cash flows represent the fair market value of the Company's proved
reserves. The Company cautions that the disclosures shown are based on
estimates of proved reserve quantities and future production schedules which
are inherently imprecise and subject to revision, and the 10% discount rate is
arbitrary. In addition, present costs and prices are used in the determinations
and no value may be assigned to probable or possible reserves.

   The following tabulation is a summary of changes between the total
standardized measure of discounted future net cash flows at the beginning and
end of each year.
<TABLE>
<CAPTION>
                                                        Years Ended December
                                                                31,
                                                        ----------------------
                                                         2000    1999    1998
                                                        ------  ------  ------
                                                             (Millions)
<S>                                                     <C>     <C>     <C>
Standardized measure of discounted future net cash
 flows at January 1.................................... $1,353  $  888  $1,166
Changes in the year resulting from:
  Sales and transfers of gas and oil produced during
   the year, less production costs.....................   (556)   (353)   (320)
  Prices and production and development costs related
   to future production................................  5,101     792    (658)
  Extensions, discoveries and other additions, less
   production and development costs....................  1,108     186     145
  Previously estimated development costs incurred
   during the year.....................................     81      57      71
  Revisions of previous quantity estimates.............   (652)   (213)     38
  Accretion of discount................................    194     121     167
  Income taxes......................................... (1,802)   (263)    181
  Purchases and sales of proved reserves in place-net..    992     265      36
  Other (principally timing of production)............. (1,293)   (127)     62
                                                        ------  ------  ------
Standardized measure of discounted future net cash
 flows at December 31.................................. $4,526  $1,353  $  888
                                                        ======  ======  ======
</TABLE>

24. Quarterly Financial Data (Unaudited)

   A summary of the quarterly results of operations for the years 2000 and 1999
follows. Because a major portion of the gas sold or transported by the
Company's distribution and transmission operations is ultimately used for space
heating, both revenue and earnings are subject to seasonal fluctuations, and
third quarter results are usually the least significant of the year for the
Company. Seasonal fluctuations are further influenced by the timing of price
relief granted under regulation to compensate for certain past cost increases.

   During the third quarter of 2000, Dominion and its subsidiaries, including
the Company, adopted a company-wide method of calculating the market related
value of pension plan assets used to determine the expected return on pension
plan assets, a component of net periodic pension cost. As a result, information
previously reported for the first and second quarters of 2000 has been restated
to reflect the change. The cumulative effect of the accounting change on prior
years, recorded as of January 1, 2000, was $31 million (net of taxes of $11
million). Income from operations previously reported for the first and second
quarters of 2000 was $116 million and $68 million, respectively. The net income
(loss) previously reported for the respective quarters was $(35) million and $7
million, respectively.

                                       72
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


<TABLE>
<CAPTION>
                                                               2000
                                                    ---------------------------
                                                             Quarter
                                                    ---------------------------
                                                    First   Second Third Fourth
                                                    ------  ------ ----- ------
                                                            (Millions)
<S>                                                 <C>     <C>    <C>   <C>
Total operating revenue and income................  $1,169   $721  $730  $1,392
Income from operations............................     134     86   108     149
Income (loss) before cumulative effect of a change
 in acounting principle...........................     (22)    20    49     166
Cumulative effect of change in accounting
 principle........................................      31    --    --      --
Net income........................................       9     20    49     166


<CAPTION>
                                                               1999
                                                    ---------------------------
                                                             Quarter
                                                    ---------------------------
                                                    First   Second Third Fourth
                                                    ------  ------ ----- ------
                                                            (Millions)
<S>                                                 <C>     <C>    <C>   <C>
Total operating revenue and income................  $1,030   $542  $477  $  925
Income from operations............................     243    (99)   37     139
Net income (loss).................................     139    (80)   11      67
</TABLE>

                                       73
<PAGE>

    ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
                              FINANCIAL DISCLOSURE

   The Company's independent accountant subsequent to the merger is Deloitte &
Touche LLP, the independent accountant for Dominion. PricewaterhouseCoopers LLP
was the independent accountant for the Company prior to the merger.

                                    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

   None

                                       74
<PAGE>

                                    PART IV

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

   (a) The following documents are filed as part of this Form 10-K:

     1. Financial Statements

       See Index on page 30.

     2. Financial Statement Schedules

<TABLE>
<CAPTION>
                                                                            Page
                                                                            ----
   <S>                                                                      <C>
   Independent Auditors' Report on Financial Statement Schedule............  77
   Schedule II--Valuation and Qualifying Accounts..........................  78
</TABLE>

   All other schedules are omitted because they are not applicable, or the
required information is shown in the financial statements or the notes thereto.

     3. Exhibits

<TABLE>
<CAPTION>
  SEC
Exhibit
Number                                       Description of Exhibit
-------                                      ----------------------
<S>      <C>
  (2)    Plan of acquisition, reorganization, arrangement, liquidation or successor:

         (2A)(i)--Amended and Restated Agreement and Plan of Merger, dated as of May 11, 1999, by and
                 between Dominion Resources, Inc. and Consolidated Natural Gas Company, (Exhibit 2,
                 Form 8-K, dated May 20, 1999, File No. 1-3196, incorporated by reference)

         (2A)(ii)--Joinder Agreement dated as of January 21, 2000 by and among Dominion Resources, Inc.,
                 Consolidated Natural Gas Company, DRI New Sub I, Inc. and DRI New Sub II, Inc.
                 (Exhibit (2A)(i) to Form 10-K for the fiscal year ended December 31, 2000,
                 File No. 1-3196, incorporated by reference)

  (3)    Certificate of Incorporation and By-Laws:

         (3A)(i)--Certificate of Incorporation of Consolidated Natural Gas Company (Exhibit (3A)(i) to
                 Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by
                 reference)

         (3A)(ii)-- Certificate of Amendment of Certificate of Incorporation, dated January 28, 2000
                 (Exhibit (3A)(ii) to Form 10-K for the fiscal year ended December 31, 1999,
                 File No. 1-3196, incorporated by reference)

         (3B)--Bylaws as in effect on December 15, 2000 (filed herewith)

  (4)    Instruments Defining the rights of Security Holders, Including Indentures:

         (4A)Indentures of Consolidated Natural Gas Company:

         (i)-- Indentures of Consolidated Natural Gas Company are incorporated by
              reference to previously filed material as indicated on the list filed herewith

         (ii)-- First Supplemental Indenture dated as of January 28, 2000 among
              Consolidated Natural Gas Company, DRI New Sub II and United States Trust
              Company of New York, as trustee, (Exhibit (4A)(ii) to Form 10-K for the fiscal
              year ended December 31, 2000, File No. 1-3196, incorporated by reference)
</TABLE>


                                       75
<PAGE>

(10) Material Contracts:

   The following exhibits are filed with this Form 10-K by being incorporated
   by reference to their filing in the Company's Forms 10-K for previous years.
   The year following the description of the exhibit indicates for each of such
   exhibits the Form 10-K, File No. 1-3196, where such exhibit was filed.

  (10A)  Form of Split Dollar Insurance Agreement between Consolidated
         Natural Gas Company and certain employees and Directors (1987)
  (10B)  Form of Supplemental Death Benefit Payment Agreement between
         Consolidated Natural Gas Company and certain employees (1987)
  (10C)  Consolidated Natural Gas Company Supplemental Retirement Benefit
         Plan (1987)
  (10D)  System Supplemental Retirement Plan for Certain Management Employees
         of Consolidated Natural Gas Company and Its Participating
         Subsidiaries, as amended December 12, 1995 (1995)
  (10E)  Consolidated Natural Gas Company Cash Incentive Bonus Deferral Plan
         (1987)
  (10F)  Form of Change of Control Employment Agreement between Consolidated
         Natural Gas Company and certain employees, dated January 19, 1999
         (1998)
  (10G)  Form of Change of Control Salary Continuation Agreement between
         Consolidated Natural Gas Company and certain employees (1989)
  (10H)  Consolidated Natural Gas Company Annual Executive Incentive Program,
         as amended December 13, 1994 (1994)
  (10H)(i) Attachment C, as amended February 18, 1997, to the Consolidated
           Natural Gas Company Annual Executive Incentive Program (1997)
  (10J)  Unfunded Supplemental Benefit Plan for Employees of Consolidated
         Natural Gas Company and Its Participating Subsidiaries Who Are Not
         Represented by a Recognized Union, as amended December 12, 1995
         (1995)
  (10K)  Form of Change of Control Employment Agreement between Consolidated
         Natural Gas Company and certain employees dated December 12, 1995
         (1995)
  (10L)  Trust Agreement between Consolidated Natural Gas Company and Mellon
         Bank (Trustee) relating to funding of certain beneficial plans for
         certain employees, dated June 1, 1995 (1996)
  (10M)  Employment Agreement between Consolidated Natural Gas Company and
         George A. Davidson, Jr. dated December 22, 1998, and related letter
         dated January 8, 1999 (1998)
  (10N)  Dominion Resources, Inc. Incentive Compensation Plan, as restated
         effective April 28, 2000 (Exhibit 99, Form S-8, Registration
         Statement, File No. 333-38396, incorporated by reference).
  (10O)  Stock Purchase Agreement, dated May 8, 2000, By and Between AGL
         Resources, Inc. as Buyer and Consolidated Natural Gas Company, as
         Seller of Virginia Natural Gas, Inc. (Exhibit 10(iii), Form 10-Q for
         the quarter ended June 30, 2000, File No. 1-8489, incorporated by
         reference).

(23) Consents of Experts and Counsel:

  (23A) Consent of Deloitte & Touche LLP (filed herewith)

  (23B) Consent of PricewaterhouseCoopers LLP (filed herewith)

   (b) Reports of Form 8-K:

None

                                       76
<PAGE>

          INDEPENDENT AUDITORS' REPORT ON FINANCIAL STATEMENT SCHEDULE

The Board of Directors
Consolidated Natural Gas Company

  We have audited the consolidated financial statements of Consolidated Natural
Gas Company and subsidiaries (the "Company") as of December 31, 2000 and have
issued our report thereon dated January 25, 200l; such report is included
elsewhere in this Form 10-K. Our audit also included the consolidated financial
statement schedule of the Company for the year ended December 31, 2000, listed
in Item 14. This consolidated financial statement schedule is the
responsibility of the Company's management. Our responsibility is to express an
opinion based on our audit. In our opinion, such consolidated financial
statement schedule, when considered in relation to the basic consolidated
financial statements taken as a whole, presents fairly in all material respects
the information set forth therein.

Deloitte & Touche LLP

Pittsburgh, Pennsylvania
January 25, 200l

                                       77
<PAGE>

                        CONSOLIDATED NATURAL GAS COMPANY

                 Schedule II--Valuation and Qualifying Accounts

<TABLE>
<CAPTION>
        Column A                Column B          Column C           Column D   Column E
        --------               ---------- ------------------------- ---------- ----------
                                                  Additions
                                          -------------------------
                               Balance at                                      Balance at
                               beginning   Charged     Charged to                end of
      Description              of period  to expense other accounts Deductions   period
      -----------              ---------- ---------- -------------- ---------- ----------
                                                    (Millions)
<S>                       <C>  <C>        <C>        <C>            <C>        <C>
Valuation and qualifying
 accounts which are
 deducted in the balance
 sheet from the assets
 to which they apply:

Allowance for doubtful
 accounts-Customers.....  1998    $29        $21          $ 4          $40(a)     $14
                          1999     14         35            3           31(a)      21
                          2000     21         51           (1)          23(a)      48
Allowance for doubtful
 accounts-
 Other..................  1998                 9                                    9
                          1999      9         (9)
                          2000                 4                         1(a)       3

Reserves:
Discontinued
 Operations.............  1998                48                        39(b)       9
                          1999      9                                    7(b)       2
                          2000      2         (2)

Liabilities for
 workforce reductions...  1998      4          9                         3(c)      10
                          1999     10         11                        12(c)       9
                          2000      9                                    6(c)       3

Liabilities for
 restructuring
 activities.............  1998
                          1999                 5                         4(c)       1
                          2000      1         50                        27(c)      24
</TABLE>
--------
(a) Represents net amounts charged off as uncollectable.

(b) Represents operating losses incurred until disposal and liabilities paid.

(c) Represents payments for workforce reductions and restructuring activities.

                                       78
<PAGE>

                                   SIGNATURES

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

                                          Consolidated Natural Gas Company

                                                   /s/ Thos. E. Capps
                                          By: _________________________________
                                                       Thos. E. Capps
                                                  Chairman of the Board of
                                                         Directors,
                                                President and Chief Executive
                                                           Officer

Date: March 16, 2001

   Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated and on the 16th day of March 2001.

<TABLE>
<CAPTION>
                 Name                                      Position
                 ----                                      --------

<S>                                    <C>
        /s/ Thos. E. Capps             Chairman of the Board of Directors, President
______________________________________  and Chief Executive Officer
            Thos. E. Capps

    /s/ Thomas F. Farrell, II          Executive Vice President and Director
______________________________________
        Thomas F. Farrell, II

     /s/ Edgar M. Roach, Jr.           Executive Vice President and Director
______________________________________
         Edgar M. Roach, Jr.

      /s/ Thomas N. Chewning           Executive Vice President and Chief Financial
______________________________________  Officer
          Thomas N. Chewning

       /s/ Steven A. Rogers            Vice President and Controller
______________________________________
           Steven A. Rogers
</TABLE>

                                       79